UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
x
Annual
Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For
the
fiscal year ended
December 31, 2005
Commission
file number
1-9735
BERRY
PETROLEUM COMPANY
(Exact
name of registrant as specified in its charter)
|
|
DELAWARE
|
|
77-0079387
|
|
|
|
(State
of incorporation or organization)
|
|
(I.R.S.
Employer Identification Number)
|
|
5201
Truxtun Avenue, Suite 300
Bakersfield,
California 93309
(Address
of principal executive offices, including zip code)
Registrant's
telephone number, including area code: (661)
616-3900
Securities
registered pursuant to Section 12(b) of the Act:
|
|
Title
of each class
|
|
Name
of each exchange on which registered
|
|
|
|
Class
A Common Stock, $.01 par value
|
|
New
York Stock Exchange
|
|
|
|
(including
associated stock purchase rights)
|
|
|
|
Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act.
YES
x
NO
o
Indicate
by check mark if the registrant is not required to file reports pursuant
to
Section 13 or Section 15(d) of the Act.
YES
o
NO
x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. YES
x
NO
o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment
to this
Form 10-K. o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filerx Accelerated
filero Non-accelerated
filero
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). YES
o
NO
x
As
of
June 30, 2005, the aggregate market value of the voting and non-voting common
stock held by non-affiliates was $962,312,197. As of February 10, 2006, the
registrant had 21,077,915 shares of Class A Common Stock outstanding. The
registrant also had 898,892 shares of Class B Stock outstanding on February
10,
2006 all of which is held by an affiliate of the registrant.
DOCUMENTS
INCORPORATED BY REFERENCE
Part
III
is incorporated by reference from the registrant's definitive Proxy Statement
for its Annual Meeting of Shareholders to be filed, pursuant to Regulation
14A,
no later than 120 days after the close of the registrant's fiscal
year.
BERRY
PETROLEUM COMPANY
PART
I
|
|
|
Page
|
|
Business
|
3
|
|
|
|
General
|
3
|
|
|
Crude
Oil and Natural Gas Marketing
|
4
|
|
|
Steaming
Operations
|
6
|
|
|
Electricity
|
7
|
|
|
Competition
|
8
|
|
|
Employees
|
8
|
|
|
Oil
and Gas Properties
|
8
|
|
|
Capital
Expenditures
|
12
|
|
|
Production
|
13
|
|
|
Acreage
and Wells
|
13
|
|
|
Drilling
Activity
|
14
|
|
|
Environmental
and Other Regulations
|
14
|
|
Forward
Looking Statements
|
15
|
|
|
Risk
Factors
|
16
|
|
|
Unresolved
Staff Comments
|
21
|
|
|
Properties
|
21
|
|
|
Legal
Proceedings
|
21
|
|
|
Submission
of Matters to a Vote of Security Holders
|
21
|
|
|
|
Executive
Officers
|
21
|
|
|
|
PART
II
|
|
|
|
|
Market
for the Registrant's Common Equity and Related Shareholder Matters
and
Issuer Purchases of Equity Securities
|
22
|
|
|
Selected
Financial Data
|
24
|
|
|
Management's
Discussion and Analysis of Financial Condition and Results of
Operations
|
26
|
|
|
Quantitative
and Qualitative Disclosures About Market Risk
|
39
|
|
|
Financial
Statements and Supplementary Data
|
41
|
|
| 43 | ||
| 44 | ||
| 45 | ||
| 46 | ||
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
|
67
|
|
|
Controls
and Procedures
|
67
|
|
|
Other
Information
|
68
|
|
|
|
|
|
PART
III
|
|
|
|
|
Directors
and Executive Officers of the Registrant
|
69
|
|
|
Executive
Compensation
|
69
|
|
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
69
|
|
|
Certain
Relationships and Related Transactions
|
69
|
|
|
Principal
Accounting Fees and Services
|
69
|
|
|
|
|
|
PART
IV
|
|
|
|
|
Exhibits,
Financial Statement Schedules
|
69
|
PART
I
General. Berry
Petroleum Company, (Berry or Company), is an independent energy company engaged
in the production, development, acquisition, exploitation and exploration
of
crude oil and natural gas. While the Company was incorporated in Delaware
in
1985 and has been a publicly traded company since 1987, it can trace its
roots
in California oil production back to 1909. Currently, Berry's principal reserves
and producing properties are located in California, Utah and Colorado. The
Company has its corporate headquarters in Bakersfield, California and a regional
office in Denver, Colorado. The Company is increasing office space in both
locations to accommodate growth. Information contained in this report on
Form
10-K reflects the business of the Company during the year ended December
31,
2005 unless noted otherwise.
The
Company’s website is located at http://www.bry.com.
The
website can be used to access recent news releases and Securities and Exchange
Commission (SEC) filings, crude oil price postings, the Company’s Annual Report,
Proxy Statement, Board committee charters, code of business conduct and ethics,
the code of ethics for senior financial officers, and other items of interest.
SEC filings, including supplemental schedules and exhibits, can also be accessed
free of charge through the SEC website at http://www.sec.gov.
Corporate
Strategy.
Berry
Petroleum Company’s mission is to increase shareholder value, primarily through
increasing the net asset value, and maximizing the cash flow and earnings
of the
Company's assets. The strategies to accomplish these goals include:
| · |
Growing
production and reserves from existing assets while managing
expenses
-
The Company intends to increase production and reserves annually
and
increase both net income and cash flow in total and per share.
The Company
will continue to focus on the further development of its properties
through developmental drilling, down-spacing, well completions,
remedial
work and by application of enhanced oil recovery (EOR) methods,
and
optimization technologies, as applicable. With respect to the California
heavy oil reserves, the Company owns three cogeneration facilities
which
are intended to provide an efficient and secure long-term supply
of steam
necessary for the economic production of heavy oil.
|
| · |
Acquiring
more light oil and natural gas assets with significant growth potential
in
the Rocky Mountain and Mid-Continent region -
The Company will compete to acquire oil and gas properties with
proved
reserves, probable reserves and/or sizeable acreage positions that
the
Company believes contain substantial reserves which can be developed
at
reasonable costs. As part of its resource diversification strategy,
Berry
desires to add natural gas production and reserves to complement
its
significant crude oil resource base. The Company has identified
the Rocky
Mountain and Mid-Continent region as its primary areas of interest
for
diversification.
|
| · |
Appraising
the Company’s exploitation and exploration projects in an expedient manner
- The
Company has been successful in adding significant acreage positions
in the
last two years with the intent of drilling exploration wells to
test the
potential of the acreage for the economic production of hydrocarbons.
Its
goal is to appraise this potential as quickly as is prudently
possible.
|
| · |
Investing
the Company’s capital in an efficient, disciplined manner
-
Investing the Company’s capital prudently is of paramount importance in
achieving long-term success. The oil and gas business is very capital
intensive so managing the business with a focus on utilizing the
available
capital on projects where it is likely to have success in increasing
production and/or reserves at attractive returns to shareholders.
A
portion of the Company’s capital will be directed to higher risk projects
that have the potential for higher
reward.
|
| · |
Utilizing
joint ventures with respected partners to enter new basins -
The
Company believes that it is beneficial to utilize the skills and
knowledge
of other industry participants upon entering new basins or areas
of
operations as it can reduce the risk and improve the success in
the
area.
|
Berry
has
the industry talent, experience, organization and motivation to accomplish
the
above strategies to fulfill its mission of increasing shareholder value.
Berry
also has the financial capacity and skill sets to accomplish these strategies.
In addition to internally generated funds, it has a $500 million unsecured
credit facility with a current borrowing base of $350 million which may be
utilized in adding prospective acreage, reserves and/or production through
acquisitions.
Proved
Reserves and Revenues. As
of
December 31, 2005, the Company's estimated proved reserves were 126 million
barrels of oil equivalent, (BOE), of which 74% are heavy crude oil, 8% light
crude oil and 18% natural gas. Nearly 40% of reserves are owned in fee.
Geographically, 74% of the Company’s reserves are located in California and 26%
in the Rocky Mountain and Mid-Continent region. Proved undeveloped reserves
make
up 28% of the Company's proved total. The projected capital to develop these
proved undeveloped reserves is $201million, at an estimated cost of
approximately $5.54 per BOE. Approximately 77% of the capital to develop
these
reserves is expected to be expended in the next five years. Production in
2005
was 8.4 million BOE, up 12% from production of 7.5 million BOE in 2004. The
Company’s reserves-to-production ratio was unchanged at 14.6 years at year-end
2005, compared to year-end 2004.
The
following table depicts all of the Company’s producing assets as of December 31,
2005. Berry operates all of the assets, except Wyoming:
|
State
|
Name
|
Type
|
Daily
Production (BOE/D)
|
%
of Daily Production
|
Proved
Reserves (BOE) in thousands
|
%
of Proved Reserves
|
Oil
& Gas Revenues before hedging (in millions)
|
%
of Oil & Gas Revenues
|
|
|
CA
|
Midway-Sunset
|
Heavy
oil
|
12,214
|
53%
|
68,071
|
54%
|
$
199
|
50%
|
|
|
UT
|
Brundage
Canyon
|
Light
oil/Natural gas
|
5,079
|
22
|
15,116
|
12
|
98
|
25
|
|
|
CA
|
Placerita
|
Heavy
oil
|
2,654
|
12
|
16,592
|
13
|
48
|
12
|
|
|
CO
|
Tri-State
|
Natural
gas
|
1,600
|
7
|
17,442
|
14
|
26
|
7
|
|
|
CA
|
Montalvo
|
Heavy
oil
|
728
|
3
|
6,869
|
5
|
12
|
3
|
|
|
CA
|
Poso
Creek
|
Heavy
oil
|
544
|
2
|
2,046
|
2
|
10
|
3
|
|
|
WY/CA
|
Various
|
Various
|
196
|
1
|
149
|
-
|
2
|
-
|
|
|
Totals
|
23,015
|
100%
|
126,285
|
100%
|
$
395
|
100%
|
The
Company continued to engage DeGolyer and MacNaughton (D&M) to appraise the
extent and value of its proved oil and gas reserves and the future net revenues
to be derived from properties of the Company for the year ended December
31,
2005. D&M is an independent oil and gas consulting firm located in Dallas,
Texas. In preparing their reports, D&M reviewed and examined geologic,
economic, engineering and other data considered applicable to properly determine
the reserves of the Company. They also examined the reasonableness of certain
economic assumptions regarding forecasted operating and development costs
and
recovery rates in light of the economic environment on December 31, 2005.
See
Supplemental Information About Oil & Gas Producing Activities (Unaudited)
for the Company's oil and gas reserve disclosures.
Acquisitions.
See
Item
7 Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
Operations.
In
California, Berry operates all of its principal oil and gas producing
properties. The Midway-Sunset, Placerita and Poso Creek fields contain
predominantly heavy crude oil which requires heat, supplied in the form of
steam, injected into the oil producing formations to reduce the oil viscosity
which allows the oil to flow to the wellbore for production. Berry utilizes
cyclic steam and/or steam flood recovery methods in all of these fields in
addition to primary recovery methods at its Montalvo field. Berry is able
to
produce its heavy oil at its Montalvo field without steam since the majority
of
the producing reservoir is at a depth in excess of 11,000 feet and the reservoir
temperature is high enough to produce the oil without the assistance of
additional heat from steam. Field operations related to oil production include
the initial recovery of the crude oil and its transport through treating
facilities into storage tanks. After the treating process is completed, which
includes removal of water and solids by mechanical, thermal and chemical
processes, the crude oil is metered through automatic custody transfer units
or
gauged before sale and subsequently transferred into crude oil pipelines
owned by other companies or transported via truck.
In
the
Rocky Mountain and Mid-Continent region, crude oil produced from the Brundage
Canyon field is transported by truck, while its gas production, net of field
usage, is transported by gathering or distribution systems to the Questar
Pipeline. Natural gas produced from the eastern Colorado Niobrara gas assets
is
transported by Company and third party gathering lines to one of two main
pipelines. The Company has a pipeline gathering system and gas compression
facilities for delivery into these two interstate gas lines in this
region.
Crude
Oil and Natural Gas Marketing
Economy.
The
global and California crude oil markets continue to remain strong. Product
prices continued to exhibit an overall-strengthening trend through 2005.
The
range of West Texas Intermediate (WTI) crude prices for 2005, based upon
NYMEX
settlements, was a low of $42.12 and a high of $69.81. The Company expects
that
crude prices will continue to be volatile in 2006.
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Average
NYMEX settlement price for WTI
|
|
$
|
56.70
|
|
$
|
41.47
|
$
|
30.99
|
|
|
|
Average
posted price for Berry’s:
|
|
|
||||||||
|
Utah
light crude oil
|
53.03
|
|
38.60
|
|
27.63
|
|||||
|
California
13 degree API heavy crude oil
|
|
|
44.36
|
|
32.84
|
|
25.33
|
|||
|
Average
crude price differential between WTI and Berry’s:
|
||||||||||
|
Utah
light crude oil
|
|
|
3.67
|
2.87
|
3.36
|
|||||
|
California
13 degree API heavy crude oil
|
12.34
|
|
8.63
|
|
5.66
|
|||||
The
above
posting prices and differentials are not necessarily amounts paid or received
by
the Company due to the contracts discussed below. While the crude oil price
differential between WTI and California’s heavy crude was fairly consistent with
historical averages in 2003 at just under $6.00 per barrel, the
differential widened dramatically during 2004 and 2005. On December 31, 2005
the
differential was $11.61 and ranged from a low of $10.27 to a high of $14.83
per
barrel during the year. Crude oil price differentials between WTI and Utah’s
light crude oil were fairly consistent during 2003, 2004 and 2005 and were
between $3 and $5 per barrel. On December 31, 2005 the differential was $4.67
and ranged from a low of $3.73 to a high of $4.77 per barrel during the year.
Oil
Contracts. Berry
markets its crude oil production to competing buyers including independent
and
major oil refining companies. Because of the Company’s ability to deliver
significant volumes of crude oil over a multi-year period, the Company secured
a
three-year sales agreement, beginning in late 2002, with a major oil company
whereby the Company sold over 90% of its California production under a
negotiated pricing mechanism. This contract ended on January 31, 2006. Pricing
in this agreement was based upon the higher of the average of the local field
posted prices plus a fixed premium, or WTI minus a fixed differential near
$6.00
per barrel. This contract allowed the Company to improve its California revenues
over the posted price by approximately $41 million and $13 million in 2005
and
2004, respectively.
On
November 21, 2005, the Company entered into a new crude oil sales contract
for
its California production for deliveries beginning February 1, 2006 and ending
January 31, 2010. The per barrel price, calculated on a monthly basis and
blended across the various producing locations, is the higher of 1) the WTI
NYMEX crude oil price less a fixed differential approximating $8.15, or 2)
heavy
oil field postings plus a premium of approximately $1.35. The initial term
of
the contract is for four years with a one-year renewal at the Company’s option.
The agreement effectively eliminates the Company’s exposure to the risk of a
widening WTI to California heavy crude price differential over the next four
years and allows the Company to effectively hedge its production based on
WTI
pricing similar to the previous contract. If this contract had been in place
during 2005, it would have allowed the Company to improve its California
revenues over the posted prices by approximately $25 million in 2005, but
$16
million below what was actually received by the Company under the contract
in
place in 2005.
Brundage
Canyon crude oil production, which is approximately 40 degree API gravity,
is
sold under contract at WTI less a fixed differential approximating $2.00
per
barrel. This contract expires on September 30, 2006. Any new contract will
be
negotiated based on market prices. The Company believes the differential
has
widened by several dollars per barrel. The majority of this crude oil, while
light, is a “paraffinic” crude, and can be processed efficiently by only a
limited number of stranded inland refineries. The production of this type
crude is increasing regionally and beginning to strain the capacity of these
refineries. Other new crude sources from the region are pressuring pricing.
If
these refineries limit the volumes of this parraffinic crude oil they are
willing to process, it could impact the marketability of this type of crude
which, for Berry, represents approximately 3,500 Bbl/D of production or
approximately 15% of total current production. The Company is investigating
its
market opportunities for this crude oil. If market prices continue to
deteriorate,
the
Company may allocate its capital expenditures to projects which produce natural
gas and crude oils with lower paraffinic content until the refinery constraint
is resolved.
Natural
Gas Marketing. Berry
markets produced natural gas from Colorado, Utah, Wyoming and
California. Generally, natural gas is sold at monthly index related prices
plus an adjustment for transportation. Certain volumes are sold at a daily
spot
related price.
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Annual
average closing price per MMBtu for:
|
|
|
||||||||
|
NYMEX
Henry Hub (HH) prompt month natural gas contract
|
$
|
9.01
|
|
$
|
6.18
|
$
|
5.84
|
|||
|
Rocky
Mountain Questar first-of-month indices (Brundage Canyon
sales)
|
6.73
|
5.05
|
4.00
|
|||||||
|
Rocky
Mountain CIG first-of-month indices (Tri-State sales)
|
6.95
|
5.17
|
4.04
|
|||||||
|
Average
natural gas price per MMBtu differential between NYMEX HH
and:
|
||||||||||
|
Questar
|
2.28
|
1.13
|
1.84
|
|||||||
|
CIG
|
2.06
|
1.01
|
1.80
|
|||||||
The
Company has physical access to interstate gas pipelines to move gas to or
from
market. To assure delivery of gas, the Company has entered into several
long-term gas transportation contracts as follows:
Firm
Transportation Summary
|
Name
|
From
|
To
|
Quantity
(Avg. MMBtu/D)
|
Term
|
2005
base costs per MMBtu
|
Remaining
contractual obligation (in thousands)
|
|||||||||||||
|
Kern
River Pipeline
|
Opal,
WY
|
Kern
County, CA
|
12,000
|
5/2003
to 4/2013
|
$
|
.6425
|
$
|
20,640
|
|||||||||||
|
Questar
Pipeline
|
Brundage
Canyon
|
Salt
Lake City, UT
|
2,500
|
9/2003
to 4/2007
|
.1739
|
211
|
|||||||||||||
|
Questar
Pipeline
|
Brundage
Canyon
|
Salt
Lake City, UT
|
2,800
|
9/2003
to 9/2007
|
.1739
|
317
|
|||||||||||||
|
KMIGT
|
Yuma
County, CO
|
Grant,
KS
|
2,500
|
1/2005
to 10/2013
|
.2270
|
1,624
|
|||||||||||||
|
Cheyenne
Plains Gas Pipeline
|
Tri-State,
CO
|
Panhandle
Eastern Pipeline
|
11,000
|
(Est.)
Q4 2006 to Q4 2016
|
.3400
|
13,662
|
|||||||||||||
|
Total
|
30,800
|
$
|
36,454
|
||||||||||||||||
Royalties.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk.
Hedging.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15
to the
financial statements.
Concentration
of Credit Risk. See
Note
4 to the financial statements.
Steaming
Operations
Cogeneration
Steam Supply. As
of
December 31, 2005, approximately 74% of the Company's proved reserves, or
93
million barrels, consisted of heavy crude oil produced from depths of less
than
2,000 feet. The Company, in pursuing its goal of being a cost-efficient heavy
oil producer in California, has remained focused on minimizing its steam
cost.
One of the main methods of keeping steam costs low is through the ownership
and
efficient operation of cogeneration facilities. Two of these cogeneration
facilities, a 38 megawatt (MW) and an 18 MW facility are located in the
Company’s Midway-Sunset field. The Company also owns a 42 MW cogeneration
facility which is located in the Placerita field. Steam generation from these
cogeneration facilities is more efficient than conventional steam generation
as
both steam and electricity are concurrently produced from a common fuel stream.
By maintaining a correlation between electricity and natural gas prices,
the
Company is able to better control its cost of producing steam.
Conventional
Steam Generation. In
addition to these cogeneration plants, the Company owns 16 conventional boilers.
The quantity of boilers operated at any point in time is dependent on 1)
the
steam volume required for the Company to achieve its targeted production
and 2)
the price of natural gas compared to the price of crude oil sold.
Total
barrels of steam per day (BSPD) capacity as of December 31, 2005 is as
follows:
|
Total
steam generation capacity of Cogeneration plants
|
38,000
|
|||
|
Additional
steam purchased under contract with third party
|
2,000
|
|||
|
Total
steam generation capacity of conventional boilers
|
43,000
|
|||
|
Total
steam capacity
|
83,000
|
The
average volume of steam injected for the years ended December 31, 2005 and
2004
was 70,032 and 69,200 BSPD, respectively.
Ownership
of these varied steam generation facilities and sources allows for maximum
operational control over the steam supply, location, and to some extent control
over the aggregated cost of steam generation. The Company’s steam supply and
flexibility are crucial for the maximization of California thermally enhanced
heavy oil production, cost control and ultimate reserve recovery.
The
Company believes that it may become necessary to add additional steam capacity
for its future development projects at Midway-Sunset and Poso Creek to allow
for
full development of its properties. The Company regularly reviews its most
economical source for obtaining additional steam to achieve its growth
objectives.
Most
of
the Company’s conventional steam generators operated in 2005 to achieve the
Company’s goal of increasing heavy oil production to record levels.
Approximately 70% of the volume of natural gas purchased to generate steam
and
electricity is based upon SoCal Border indices. While there are no
transportation charges for gas purchased at the SoCal Border location, all
locations except the central portion of the Midway-Sunset field pay
distribution/transportation charges to either SoCal Gas or Pacific Gas &
Electric
(PG&E) to have the gas delivered to the field. The remaining 30% of supply
volume is purchased in Wyoming and moved to the Midway-Sunset field using
the
Company’s firm transport on the Kern River Pipeline. This gas is purchased based
upon the Rocky Mountain Northwest Pipeline (NWPL) index.
|
|
|
2005
|
|
2004
|
|
2003
|
|||
|
Average
SoCal Border Monthly Index Price per MMBtu
|
|
$
|
7.37
|
|
$
|
5.60
|
$
|
5.00
|
|
|
Average
Rocky Mountain NWPL Monthly Index Price per MMBtu (*contract began
May
2003)
|
6.96
|
5.24
|
4.34*
|
||||||
The
Company historically was a net purchaser of natural gas and thus its net
income
was negatively impacted when natural gas prices rose higher than its oil
equivalent. In 2005, due to its eastern Colorado Niobrara gas acquisition,
the
Company on a gas balance basis achieved parity. Thus, going forward, the
Company
is a net seller of gas and operationally should benefit when gas prices are
higher. The balance between natural gas (MMBtu/D) consumed and produced during
the month of December 2005 was approximately as follows:
|
Natural
gas consumed in:
|
|||
|
Cogeneration
operations
|
27,000
|
||
|
Conventional
boilers
|
11,000
|
||
|
Total
natural gas consumed
|
38,000
|
||
|
Less:
Company’s estimate of approximate natural gas consumed to produce
electricity (1)
|
(20,000)
|
||
|
Total
approximate natural gas volumes consumed to produce steam
|
18,000
|
||
|
Natural
gas produced:
|
|||
|
Tri-State
(Niobrara)
|
11,900
|
||
|
Brundage
Canyon (associated gas)
|
11,400
|
||
|
Other
|
1,700
|
||
|
Total
natural gas volumes produced in operations
|
25,000
|
(1)
The Company estimates this volume based on electricity revenues divided by
the
purchase price, including transportation, per MMBtu for the respective
period.
Electricity.
Generation.
The
total
annual average electrical generation of the Company’s three cogeneration
facilities is approximately 93 megawatts (MW), of which the Company consumes
approximately 8 MW for use in its operations. Each facility is centrally
located
on an oil producing property such that the steam generated by the facility
is
capable of being delivered to the wells that require steam for the enhanced
oil
recovery process. The Company’s investment in its cogeneration facilities has
been for the express purpose of lowering the steam costs in its heavy oil
operations and securing operating control of the respective steam generation.
Expenses of operating the cogeneration plants are analyzed regularly to
determine whether they are advantageous versus conventional steam boilers.
Cogeneration costs are allocated between electricity generation and oil and
gas
operations based on the conversion efficiency (of fuel to electricity and
steam)
of each cogeneration facility and certain direct costs to produce steam.
Cogeneration costs allocated to electricity will vary based on, among other
factors, the thermal efficiency of the Company's cogeneration plants, the
price
of natural gas used for fuel in generating electricity and steam, and the
terms
of the Company's power contracts. The Company views any profit or loss from
the
generation of electricity as a decrease or increase, respectively, to its
total
cost of producing its heavy oil in California. DD&A related to the Company's
cogeneration facilities is allocated between electricity operations and oil
and
gas operations using a similar allocation method.
Sales
Contracts. Historically,
the Company has sold electricity produced by its cogeneration facilities
to two
California public utilities, Southern California Edison Company (Edison)
and
PG&E, under long-term contracts. These contracts are referred to as Standard
Offer (SO) contracts under which the Company is paid an energy payment that
reflects the utility’s Short Run Avoided Cost (SRAC) plus a capacity payment
that reflects a recovery of capital expenditures that would otherwise have
been
made by the utility. An SO2 contract is more beneficial as it receives a
higher
capacity payment than an SO1 contract. The SRAC energy price is currently
determined by a formula that reflects the utility’s marginal fuel cost and a
conversion efficiency that represents a hypothetical resource to generate
electricity in the absence of the cogenerator. During most periods natural
gas
is the marginal fuel for California utilities so this formula provides a
hedge
against the Company’s cost of gas to produce electricity and steam in its
cogeneration facilities. A proceeding is now underway at the California Public
Utilities Commission (CPUC) to review and revise the methodology used to
determine SRAC energy prices. This proceeding is currently scheduled to be
completed by the third quarter of 2006. There is no assurance that any new
methodology will continue to provide a hedge against the Company’s fuel cost or
that a revised pricing mechanism will be as beneficial as the current contract
pricing.
The
original SO contract for Placerita Unit 1 continues in effect through March
2009, which makes up approximately 17% of total approximate barrels of steam
per
day. The modified SRAC pricing terms of this contract reflect a fixed energy
price of 5.37 cents/kilowatt hour (KWh) through June 2006, at which time
the
energy price reverts to the SRAC pricing methodology. The Company will be
paid a
reduced capacity payment that is fixed through the term of the contract.
In
December 2004, the Company executed a five-year SO contract with Edison for
the
Placerita Unit 2 facility, and five-year SO contracts with PG&E for the
Cogen 18 and Cogen 38 facilities, each effective January 1, 2005. Pursuant
to
these contracts, the Company is paid the purchasing utility’s SRAC energy price
and a capacity payment that is subject to adjustment from time to time by
the
CPUC. Edison and PG&E challenged, in the California Court of Appeals, the
legality of the CPUC decision that ordered the utilities to enter into these
five-year SO contracts, and similar one-year SO contracts that were ordered
for
2004. The Court ruled that the CPUC had the right to order the utilities
to
execute these contracts. The Court also ruled that the CPUC was obligated
to
review the prices paid under the contracts and to retroactively adjust the
prices to the extent it was later determined that such prices did not comply
with the requirements of the Public Utilities Regulatory Policy Act of 1978,
as
amended (PURPA).
The
Company believes that Qualifying Facilities (QF), such as the Company's
facilities, provide an important source of distributive power generation
into
California's electricity grid, and as such, that the Company's facilities
will
be economic to operate for at least the current five-year contract term.
Based
on the current pricing mechanism for its electricity under the contracts
(which
includes electricity purchased for internal use), the Company expects that
its
electricity revenues will be in the $50 million to $60 million range for
2006.
Facility
and Contract Summary
|
Location
and Facility
|
Type
of Contract
|
Purchaser
|
Contract
Expiration
|
Approximate
Megawatts Available for Sale
|
Approximate
Megawatts Consumed in Operations
|
Approximate
Barrels of Steam Per Day
|
|
Placerita
|
|
|
|
|
|
|
|
Placerita
Unit 1
|
SO2
|
Edison
|
Jun-06
(1)
|
20
|
-
|
6,600
|
|
Placerita
Unit 2
|
SO1
|
Edison
|
Dec-09
|
16
|
4
|
6,700
|
|
|
|
|
|
|
|
|
|
Midway-Sunset
|
|
|
|
|
|
|
|
Cogen
18
|
SO1
|
PG&E
|
Dec-09
|
12
|
4
|
6,600
|
|
Cogen
38
|
SO1
|
PG&E
|
Dec-09
|
37
|
-
|
18,000
|
(1)
After expiration at June 2006, the contract will convert to SO1 through its
expiration at March 2009.
Competition. The
oil
and gas industry is highly competitive. As an independent producer, the Company
does not own any refining or retail outlets and, therefore, it has little
control over the price it receives for its crude oil. As such, higher costs,
fees and taxes assessed at the producer level cannot necessarily be passed
on to
the Company's customers. In acquisition activities, significant competition
exists as integrated and independent companies and individual producers are
active bidders for desirable oil and gas properties and prospective acreage.
Although many of these competitors have greater financial and other resources
than the Company, Management believes that Berry is in a position to compete
effectively due to its efficient operating cost structure, transaction
flexibility, strong financial position, experience and
determination.
Employees. On
December 31, 2005, the Company had 209 full-time employees, up from 156
full-time employees on December 31, 2004.
Berry’s
Net Oil and Gas Producing Properties at December 31,
2005.
|
Name
|
%
Average Working Interest
|
Total
Net Acres
|
Proved
Reserves (BOE) in thousands
|
Proved
Developed Reserves (BOE) in thousands
|
%
of Total Proved Reserves
|
Proved
Undeveloped Reserves (BOE) in thousands
|
%
of Total Proved Reserves
|
Average
Depth of Producing Reservoir (feet)
|
|
Midway-Sunset,
CA
|
99
|
4,836
|
68,071
|
60,627
|
48%
|
7,443
|
6%
|
1,200
|
|
Brundage
Canyon, UT
|
100
|
45,420
|
15,116
|
8,554
|
7
|
6,561
|
5
|
6,000
|
|
Placerita,
CA
|
100
|
965
|
16,592
|
7,462
|
6
|
9,130
|
7
|
1,800
|
|
Tri-State,
CO/KS/NE
|
50
|
315,473
|
17,442
|
8,411
|
7
|
9,031
|
7
|
2,600
|
|
Montalvo,
CA
|
100
|
8,563
|
6,869
|
2,811
|
2
|
4,059
|
3
|
11,500
|
|
Poso
Creek, CA
|
100
|
680
|
2,046
|
2,046
|
2
|
-
|
-
|
1,200
|
|
Various
|
15
|
815
|
149
|
150
|
-
|
-
|
-
|
various
|
|
Totals
|
376,752
|
126,285
|
90,061
|
72%
|
36,224
|
28%
|
San
Joaquin Valley Basin
Midway-Sunset,
California
- Berry
owns and operates working interests in 38 properties, including 23 owned
in fee,
in the Midway-Sunset field. Production from this field relies on thermal
enhanced oil recovery (EOR) methods, primarily cyclic steaming.
2005
-
Development activities at Midway-Sunset continued to be focused on horizontal
drilling to improve ultimate recovery of original oil-in-place, reduce the
development and operating costs of properties and to accelerate production.
2006
-
Capital of $40 million ($15 million for development and $25 million for
exploration/appraisal) is directed to 1) development - maximizing the recovery
from horizontal wells, improving steam efficiency and expanding two steam
flood
projects and 2) exploration/appraisal - expanding of the Diatomite project
which
includes up to 50 wells and related facilities.
Poso
Creek, California
- Berry
acquired these properties beginning in 2003 and is evaluating the potential
for
thermal EOR.
2005
-
The Company initiated a steam flood on the property.
2006
-
Capital of $5 million is directed at drilling infill wells and, upon success,
expanding the steam flood area.
Los
Angeles Basin
Placerita,
California -
Berry
owns and operates working interests in 13 properties, including 9 leases
and 4
fee properties, in the Placerita field. Production relies on thermal recovery
methods, primarily steam flooding.
2005
-
Began
major recompletion effort in mature steam flood and drilled 10 wells on northern
acreage.
2006
-
Capital of $8 million is directed at converting northern leases to steam
flood,
expanding another steam flood project and focusing on utilizing optimization
technology to improve recovery.
Ventura
Basin
Montalvo,
California -
Berry
owns 6 leases in the Ventura Basin comprising the entire Montalvo field.
The
State of California is the lessor for 2 of these leases. The wells produce
heavy
oil and due to the depth of the reservoir, steam injection is not necessary.
2005
-
Berry
performed several well recompletions.
2006
-
Capital of $8 million is directed at testing the western Sespe reservoir
through
additional drilling and adding production in the Colonia zone.
Uinta
Basin
Brundage
Canyon, Utah - The
Brundage Canyon leasehold in Duchesne County, northeastern Utah consists
of
federal, tribal and private leases.
2005
-
The
Company continued its focus on development of the Brundage Canyon property,
drilling 53 wells including 33 infill wells to validate 40-acre spacing.
2006
-
Capital of $58 million is directed at continuing the development of the Green
River formation, including testing 20-acre infills.
Lake
Canyon Prospect, Utah -
The
Company holds, with an industry partner, a 169,000 gross acre block which
is
located immediately west of the Company’s Brundage Canyon producing properties.
The Company will drill and operate the shallow wells which target light oil
and
natural gas in the Green River formation and retain up to a 75% working
interest. The Company's partner will drill and operate the deep wells which
target natural gas in the Mesaverde and Wasatch formations. Berry will hold
up
to a 25% working interest in these deep wells. The Ute Tribe has the option
to
participate in each well and obtain a 25% working interest which would reduce
the Company’s and its partner’s participation. The Ute Tribe did participate in
the first two shallow Green River wells.
2005
-
The
Company drilled 2 shallow Green River oil and gas wells and participated
in a 57
square mile 3-D seismic survey. In October 2005, the Company’s partner began
drilling a deep Mesaverde gas test well that reached targeted depth of 14,500
feet in December. This deep well is being evaluated. In January 2006, the
Company announced that its 2 shallow wells have commercial quantities of
oil and
gas.
2006
-
Capital of $4 million is directed at an additional 4 shallow wells and
participation in deep Mesaverde tests. Upon further success with the shallow
wells, the Company will accelerate development and capital on this
project.
Coyote
Flats Prospect, Utah -
In
December 2004, the Company entered into a development agreement with an industry
partner to develop their Coyote Flats prospect. The property is located
approximately 45 miles southwest of the Company’s Brundage Canyon property. The
Company is obligated to drill four test wells into the Ferron sand to a depth
of
approximately 7,500 feet and also drill a five well Emery coalbed methane
(CBM)
pilot, found at approximately 4,500 feet. Upon the completion of this total
nine
well drilling program, the Company will earn a 50% working interest in the
approximately 69,250 gross (33,500 net) acres. The Company expects to complete
this nine well drilling program in 2006.
2005
-
The
Company has drilled 3 Ferron sand test wells in 2005, one of which was a
dry
hole. The Company began its CBM development with 1 well drilled.
2006
-
Capital of $5 million is directed at fulfilling Berry’s obligation wells, which
consists of four CBM wells and one Ferron well. A gas pipeline is also planned
to tie in gas production for sale in mid-summer.
Big
Wash Unit, Utah
- The
Company, and an industry partner, owns working interest in 3 acreage blocks,
the
largest being the Big Wash Unit, which is located one mile southeast of Brundage
Canyon.
2005
-
Participated in one deep Mesaverde test in 2005, and the well (net working
interest to Berry of 16%) is an economic producer.
2006
-
Capital of $2 million is directed at participating in one exploratory gas
well
in the deep Mesaverde and one exploratory oil well in the shallow Green River
formation.
Denver-Julesburg
Basin
Tri-State
Area (includes eastern Colorado producing assets) -
This
area is comprised of the following three acquisitions during 2005 totaling
approximately 315,000 net acres, including approximately 100,000 net acres
of
producing acreage:
| · |
Niobrara
gas producing assets in Yuma County in northeastern Colorado in
which the
Company has approximately 52% working interest.
|
| · |
Eastern
Colorado, western Kansas and southwestern Nebraska in which the
Company
has approximately 50% working interest. The Company’s joint venture (JV)
will apply seismic technologies to explore and, if successful,
develop the
Niobrara formation for gas and Sharon Springs shale gas, which
lies at
less than 2,000 feet, and apply seismic technologies to evaluate
oil
potential in the Pennsylvanian formations at depths of 4,000 feet
to 4,800
feet.
|
| · |
Colorado’s
Phillips and Sedgwick Counties in which the Company has approximately
50%
working interest. This Niobrara leasehold position is adjacent
to and
immediately north of Berry’s producing natural gas assets in Yuma County.
|
2005
-
In 2005,
the Company drilled approximately 103 gross wells as part of its ongoing
development program and the initiation of the 40-acre infill program from
the
existing 80-acre development. The JV’s initial exploratory wells at Prairie Star
Sherman County, Kansas are commercial. Additionally, the JV drilled 7 gross
wells (4 net) in 2005 at Prairie Star.
2006
-
Capital of $25 million ($17 million development and $8 million exploration)
is
directed at drilling over 160 wells to add production from both proved
undeveloped and probable reserves and over 30 exploratory wells, based on
various seismic data and interpretation. The Company will also participate
in at
least five 3-D seismic surveys covering in excess of 250 square
miles.
Williston
Basin
Bakken
Play, North Dakota -
In 2005,
the Company completed several transactions and Berry now has total working
interests of 50% in 186,000 gross acres (46,000 net) located in the Williston
Basin in North Dakota. These acquisitions, totaling approximately $9 million,
provide the Company an entry into the emerging Bakken oil play in the Williston
Basin. The acreage covers several contiguous blocks located primarily on
the
eastern flank of the Nesson Anticline. Development activity in the Middle
Bakken
play is generally expanding to the area surrounding the Nesson Anticline.
2005
-
The
Company participated in one exploratory well which is undergoing
evaluation.
2006
-
Capital of $4 million is directed at participating in at least four exploratory
horizontal wells. Berry does not anticipate being the operator of any of
these
wells.
Piceance
Basin
Grand
Valley, Colorado -
On
January 27, 2006 the Company announced that it had entered into an agreement
with a private seller to acquire a 50% working interest in natural gas assets
(6,314 gross acres) in the Piceance Basin of western Colorado for approximately
$150 million. Berry internally estimates 26 billion cubic feet (Bcf) of proved
reserves. Berry has identified over 600 drilling locations based on 10-acre
development. Berry will be targeting gas in the Williams Fork section of
the
Mesaverde formation. The Company increased its 2006 capital budget by an
additional $48 million to $208 million to develop this resource. There are
two
drilling rigs dedicated to this project and based on the productivity of
this
acreage and surrounding producing operations, Berry is seeking to add additional
drilling rigs to accelerate development. Estimated production, net to Berry’s
interests as of March 1, 2006 is 1 million cubic feet per day. The transaction
closed on February 28, 2006.
2006
-
Capital of $48 million is directed at beginning the extensive development
of the
acreage. The Company intends to drill over 30 wells in 2006 and, depending
on
rig availability and commodity prices, may increase its capital committed
to the
project.
The
following is a summary of the Company's capital expenditures incurred during
2005 and 2004 and budgeted capital expenditures for 2006:
CAPITAL
EXPENDITURES SUMMARY
(in
thousands)
|
|
2006
|
2005
|
|
2004
|
|
||||
|
|
(Budgeted)
(1)
|
|
|
|
|
|
|||
|
CALIFORNIA
|
|
|
|
|
|
|
|||
|
Midway-Sunset
field
|
|
|
|
|
|
|
|||
|
New
wells
|
$
|
23,380
|
|
$
|
17,369
|
|
$
|
11,376
|
|
|
Remedials/workovers
|
|
1,145
|
|
|
1,079
|
|
|
1,415
|
|
|
Facilities
- oil & gas
|
|
14,493
|
|
|
7,879
|
|
|
4,045
|
|
|
Facilities
- cogeneration
|
|
543
|
|
|
3,053
|
|
|
1,055
|
|
|
General
|
|
540
|
|
|
1,271
|
|
|
2,144
|
|
|
|
|
40,101
|
|
|
30,651
|
|
|
20,035
|
|
|
Other
California fields
|
|
|
|
|
|
|
|
|
|
|
New
wells
|
|
10,647
|
|
|
6,965
|
|
|
426
|
|
|
Remedials/workovers
|
|
2,650
|
|
|
5,303
|
|
|
1,589
|
|
|
Facilities
- oil & gas
|
|
7,202
|
|
|
3,677
|
|
|
3,416
|
|
|
Facilities
- cogeneration
|
|
400
|
|
|
1,446
|
|
|
555
|
|
|
General
|
110
|
46
|
-
|
||||||
|
|
|
21,009
|
|
|
17,437
|
|
|
5,986
|
|
|
Total
California
|
|
61,110
|
|
|
48,088
|
|
|
26,021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCKY
MOUNTAIN AND MID-CONTINENT
|
|
|
|
|
|
|
|
|
|
|
Uinta
Basin
|
|
|
|
|
|
|
|
|
|
|
New
wells
|
|
64,100
|
|
|
50,354
|
|
|
39,467
|
|
|
Remedials/workovers
|
|
1,496
|
|
|
3,415
|
|
|
4,597
|
|
|
Facilities
|
|
2,500
|
|
|
1,860
|
|
|
1,979
|
|
|
General
|
552
|
4
|
-
|
||||||
|
|
|
68,648
|
|
|
55,633
|
|
|
46,043
|
|
|
Piceance
Basin
|
|
|
|
|
|
|
|
|
|
|
New
wells
|
47,615
|
-
|
-
|
||||||
|
|
|
47,615
|
|
|
-
|
|
|
-
|
|
|
DJ
Basin
|
|
|
|
|
|
|
|
|
|
|
New
wells/workovers
|
|
14,819
|
|
|
11,257
|
|
|
-
|
|
|
Remedials/workovers
|
275
|
693
|
-
|
||||||
|
Facilities
|
|
5,215
|
|
|
2,569
|
|
|
-
|
|
|
General
|
4,838
|
387
|
-
|
||||||
|
Land
and seismic
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
25,147
|
|
|
14,906
|
|
|
-
|
|
|
Williston
Basin - New wells
|
|
4,400
|
|
|
-
|
|
|
161
|
|
|
Total
Rocky Mountain and
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent
|
|
145,810
|
|
|
70,539
|
|
|
46,204
|
|
|
Other
Fixed Assets
|
|
770
|
|
|
647
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
$
|
207,690
|
|
$
|
119,274
|
|
$
|
72,225
|
|
(1) Budgeted
capital expenditures may be adjusted for numerous reasons including, but
not
limited to, oil, and natural gas price levels and equipment availability,
permitting and regulatory issues. See Item
7 Management's Discussion and Analysis of Financial Condition and Results
of
Operations.
Production. The
following table sets forth certain information regarding production for the
years ended December 31, as indicated:
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Net
annual production: (1)
|
|
|
|
|
|
|
|
|||
|
Oil
(Mbbl)
|
|
|
7,081
|
|
|
7,044
|
|
|
5,827
|
|
|
Gas
(MMcf)
|
|
|
7,919
|
|
|
2,839
|
|
|
1,277
|
|
|
Total
equivalent barrels (MBOE) (2)
|
|
|
8,401
|
|
|
7,517
|
|
|
6,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price:
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl) before hedging
|
|
$
|
47.04
|
|
$
|
33.43
|
|
$
|
24.41
|
|
|
Oil
(per Bbl) after hedging
|
|
|
40.83
|
|
|
29.89
|
|
|
22.37
|
|
|
Gas
(per Mcf) before hedging
|
|
|
7.88
|
|
|
6.13
|
|
|
4.40
|
|
|
Gas
(per Mcf) after hedging
|
|
|
7.73
|
|
|
6.12
|
|
|
4.43
|
|
|
Per
BOE before hedging
|
|
|
47.01
|
|
|
33.64
|
|
|
24.48
|
|
|
Per
BOE after hedging
|
|
|
41.62
|
|
|
30.32
|
|
|
22.52
|
|
|
Average
operating cost - oil and gas production (per BOE)
|
|
|
11.79
|
|
|
10.09
|
|
|
9.57
|
|
Mbbl
-
Thousands of barrels
MMcf
-
Million cubic feet
BOE
-
Barrels of oil equivalent
MBOE
-
Thousand barrels of oil equivalent
(1)
Net production represents that owned by Berry and produced to its
interests.
(2)
Equivalent oil and gas information is at a ratio of 6 thousand cubic feet
(Mcf)
of natural gas to 1 barrel (Bbl) of oil. A barrel of oil is equivalent to
42
U.S. gallons
Acreage
and Wells. As
of
December 31, 2005, the Company's properties accounted for the following
developed and undeveloped acres:
|
|
|
Developed
Acres
|
|
Undeveloped
Acres
|
|
Total
|
|
||||||||||||
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
||||||
|
California
|
|
|
8,007
|
8,007
|
7,038
|
7,038
|
15,045
|
15,045
|
|
||||||||||
|
Colorado
|
79,910
|
67,302
|
162,966
|
77,029
|
242,876
|
144,331
|
|||||||||||||
|
Illinois
|
|
|
-
|
-
|
35,481
|
33,249
|
35,481
|
33,249
|
|
||||||||||
|
Kansas
|
|
|
-
|
-
|
424,885
|
275,494
|
424,885
|
275,494
|
|
||||||||||
|
Nebraska
|
-
|
-
|
124,025
|
57,756
|
124,025
|
57,756
|
|||||||||||||
|
North
Dakota
|
-
|
-
|
185,976
|
46,252
|
185,976
|
46,252
|
|||||||||||||
|
Utah
(1) (2)
|
|
|
9,520
|
9,360
|
99,033
|
66,686
|
108,553
|
76,046
|
|
||||||||||
|
Wyoming
|
|
3,800
|
750
|
3,146
|
1,130
|
6,946
|
1,880
|
|
|||||||||||
|
Other
|
|
|
80
|
19
|
-
|
-
|
80
|
19
|
|
||||||||||
|
|
|
|
101,317
|
85,438
|
1,042,550
|
564,634
|
1,143,867
|
650,072
|
|
||||||||||
(1)
Includes 44,583 gross undeveloped acres (22,292 net) where the Company has
an
interest in 75% of the deep rights and 25% of the shallow
rights.
(2)
Does not include 125,000 gross (70,000 net) acres, 125,000 gross (23,000
net)
acres and 69,000 gross (34,000 net) acres at Lake Canyon (shallow), Lake
Canyon
(deep) and Coyote Flats, respectively, which the Company can earn upon
fulfilling specific drilling obligations.
Gross
acres represent acres in which Berry has a working interest; net acres represent
Berry's aggregate working interests in the gross acres.
As
of
December 31, 2005, the Company has 2,035 gross oil wells (1,951 net) and
976
gross gas wells (419 net). Gross wells represent the total number of wells
in
which Berry has a working interest. Net wells represent the number of gross
wells multiplied by the percentages of the working interests owned by Berry.
One
or more completions in the same bore hole are counted as one well. Any well
in
which one of the multiple completions is an oil completion is classified
as an
oil well.
Drilling
Activity. The
following table sets forth certain information regarding Berry's drilling
activities for the periods indicated:
|
|
|
2005
|
|
2004
|
|
2003
|
|
||||||||||||
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
||||||
|
Exploratory
wells drilled (2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Productive
|
|
|
13
|
6
|
|
|
5
|
|
|
5
|
|
|
-
|
|
|
-
|
|
||
|
Dry
(1)
|
|
|
1
|
1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
||
|
Development
wells drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Productive
|
|
|
213
|
176
|
|
|
123
|
|
|
111
|
|
|
121
|
|
|
119
|
|
||
|
Dry
(1)
|
|
|
7
|
5
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
1
|
|
||
|
Total
wells drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Productive
|
|
|
226
|
182
|
|
|
128
|
|
|
116
|
|
|
121
|
|
|
119
|
|
||
|
Dry
(1)
|
|
|
8
|
6
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
1
|
|
||
(1)
A
dry well is a well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
(2)
Does not include one gross well drilled by the Company’s industry partner that
is being evaluated at December 31, 2005.
|
|
|
2005
|
||||
|
|
|
Gross
|
|
Net
|
||
|
Total
productive wells drilled:
|
|
|
||||
|
Oil
|
|
|
113
|
111
|
||
|
Gas
|
|
|
113
|
71
|
||
Dry
hole, abandonment and impairment.
See
Item
7 Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
California
Drilling Rig.
The
Company entered into a three-year drilling contract for the services of an
automated drilling rig. This rig provides a means for Berry to meet at least
half of its California new well drilling needs for the next three years,
with
the other half being met by conventional drilling rigs. The three-year drilling
contract begins upon commissioning of the rig which is expected in the second
quarter of 2006.
Rocky
Mountain and Mid-Continent Region Drilling Rigs.
During
2005, the Company purchased two drilling rigs. The first rig is leased to
a
drilling company under a three year contract, while the second rig is currently
being refurbished in preparation for leasing under a similar drilling contract.
Owning these rigs allows the Company to successfully meet a portion of its
drilling needs in the Uinta Basin over the next several years, while both
rigs
carry purchase options available to the drilling company.
Other.
At
year-end, the Company had no subsidiaries, no special purpose entities and
no
off-balance sheet debt. The Company did not enter into any significant related
party transactions in 2005. See Note 17 to the financial statements for
discussion regarding Canyon Drilling, LLC.
Environmental
and Other Regulations. Berry
Petroleum Company is committed to responsible management of the environment,
health and safety, as these areas relate to the Company’s operations. The
Company strives to achieve the long-term goal of sustainable development
within
the framework of sound environmental, health and safety practices and standards.
Berry makes environmental, health and safety protection an integral part
of all
business activities, from the acquisition and management of its resources
through the decommissioning and reclamation of its wells and
facilities.
All
facets of the Company's operations are affected by a myriad of federal, state,
regional and local laws, rules and regulations. Berry is further affected
by
changes in such laws and by constantly changing administrative regulations.
Furthermore, government agencies may impose substantial liabilities if the
Company fails to comply with such regulations or for any contamination resulting
from the Company's operations. Therefore, Berry has programs in place to
identify and manage known risks, to train employees in the proper performance
of
their duties and to incorporate viable new technologies into its operations.
The
costs incurred to ensure
compliance
with environmental, health and safety laws and other regulations are normal
operating expenses and are not material to the Company’s operating cost. There
can be no assurances, however, that changes in, or additions to, laws and
regulations regarding the protection of the environment will not have an
impact
in the future. Berry maintains insurance coverage that it believes is customary
in the industry although it is not fully insured against all environmental
or
other risks.
Regulation
of Oil and Gas. The
oil
and gas industry, including the Company’s operations, is extensively regulated
by numerous federal, state and local authorities, and with respect to tribal
lands, and one Native American tribe.
These
types of regulation include requiring permits for the drilling of wells,
drilling bonds and reports concerning operations. Regulations may also govern
the location of wells, the method of drilling and casing wells, the rates
of
production or "allowables," the surface use and restoration of properties
upon
which wells are drilled, the plugging and abandoning of wells, and notice
to surface owners and other third parties. Certain laws and regulations may
limit the amount of oil and natural gas the Company can produce from its
wells
or limit the number of wells or the locations at which it can drill. The
Company
is also subject to various laws and regulations pertaining to Native American
tribal surface ownership, Native American oil and gas leases and other
exploration agreements, fees, taxes, and other burdens, obligations and issues
unique to oil and gas ownership and operations within Native American
reservations.
Federal
Energy Regulation. The
enactment of PURPA, as amended, and the adoption of regulations thereunder
by
the Federal Energy Regulation Commission (FERC) provided incentives for the
development of cogeneration facilities such as those owned by the Company.
A
domestic electricity generating project must be a QF under FERC regulations
in
order to take advantage of certain rate and regulatory incentives provided
by
PURPA.
PURPA
provides two primary benefits to QFs. First, QFs generally are relieved of
compliance with extensive federal and state regulations that control the
financial structure of an electricity generating plant and the prices and
terms
on which electricity may be sold by the plant. Second, FERC’s regulations
promulgated under PURPA require that electric utilities purchase electricity
generated by QFs at a price based on the purchasing utility’s avoided cost, and
that the utility sell back-up power to the QF on a non-discriminatory basis.
The
term "avoided cost" is defined as the incremental cost to an electric utility
of
electric energy or capacity, or both, which, but for the purchase from QFs,
such
utility would generate for itself or purchase from another source. The Energy
Policy Act of 2005 amends PURPA to allow a utility to petition FERC to be
relieved of its obligation to enter into any new contracts with QFs if the
FERC
determines that a competitive electricity market is available to QFs in its
service territory. This amendment does not affect any of the Company’s current
SO contracts. FERC regulations also permit QFs and utilities to negotiate
agreements for utility purchases
of power at rates lower than the utilities’ avoided costs. In California, the
utility’s avoided cost is generally referred to as Short Run Avoided Cost or
SRAC.
In
order
to be a QF, a cogeneration facility must produce not only electricity, but
also
useful thermal energy for use in an industrial or commercial process for
heating
or cooling applications in certain proportions to the facility’s total energy
output, and must meet certain energy efficiency standards. Each of the Company’s
cogeneration facilities is a QF, pursuant to PURPA.
State
Energy Regulation. The
CPUC
has broad authority to regulate both the rates charged by, and the financial
activities of, electric utilities operating in this state and to promulgate
regulation for implementation of PURPA. Since a power sales agreement becomes
a
part of a utility’s cost structure (generally reflected in its retail rates),
power sales agreements with independent electricity producers, such as the
Company, are potentially under the regulatory purview of the CPUC and in
particular the process by which the utility has entered into the power sales
agreements. While the Company is not subject to regulation by the CPUC, the
CPUC's implementation of PURPA is important to the Company.
Forward
Looking Statements
"Safe
harbor under the Private Securities Litigation Reform Act of 1995:” Any
statements in this Form 10-K that are not historical facts are forward-looking
statements that involve risks and uncertainties. Words such as “will,” “might,”
“intend,” “continue,” “target(s),” “expect,” “achieve,” “strategy,” “future,”
“may,” “could,” “goal(s),” or other comparable words or phrases or the negative
of those words, and other words of similar meaning indicate forward-looking
statements and important factors which could affect actual results.
Forward-looking statements are made based on management’s current expectations
and beliefs concerning future developments and their potential effects upon
Berry Petroleum Company. These items are discussed at length in Part I, Item
1A
on page 16 of this Form 10-K filed with the Securities and Exchange Commission,
under the heading “Other Factors Affecting the Company's Business and Financial
Results" in the section titled "Management’s Discussion and Analysis of
Financial Condition and Results of Operations.”
Other
Factors Affecting the Company's Business and Financial
Results
Oil
and gas prices fluctuate widely, and low prices for an extended period of
time
are likely to have a material adverse impact on our
business.
Our
revenues, profitability and future growth and reserve calculations depend
substantially on reasonable prices for oil and gas. These prices also affect
the
amount of our cash flow available for capital expenditures and our ability
to
borrow and raise additional capital. The amount we can borrow under our credit
facility is subject to periodic asset redeterminations based in part on changing
expectations of future crude oil and natural gas prices. Lower prices may
also
reduce the amount of oil and gas that we can produce economically.
Among
the
factors that can cause fluctuations are:
| · |
domestic
and foreign supply of oil and natural
gas;
|
| · |
price
and availability of alternative
fuels;
|
| · |
weather
conditions;
|
| · |
level
of consumer demand;
|
| · |
price
of foreign imports;
|
| · |
world-wide
economic conditions;
|
| · |
political
conditions in oil and gas producing regions;
and
|
| · |
domestic
and foreign governmental
regulations.
|
The
Company has crude oil hedges on 10,000 Bbl/D for 4 years beginning in 2006.
We
have an oil collar in place based on WTI pricing with a $47.50 floor and
a $70
ceiling.
Our
heavy crude in California is less economic than lighter crude oil and natural
gas. As
of
December 31, 2005, approximately 74% of our proved reserves or 93 million
barrels, consisted of heavy oil, light crude oil represented 8% and natural
gas
represented 18% of our oil and gas reserves. Our objective is to diversify
our
predominantly heavy crude oil base with light crude oil and natural gas.
In
November 2005, the Company entered into a new crude oil sales contract for
its
California production for deliveries beginning February 1, 2006 and ending
January 31, 2010. The per barrel price, calculated on a monthly basis and
blended across the various producing locations, is the higher of 1) the WTI
NYMEX crude oil price less a fixed differential approximating $8.15, or 2)
heavy
oil field postings plus a premium of approximately $1.35.
A
widening of commodity differentials may adversely impact our revenues and
per
barrel economics. Both
our
produced crude oil and natural gas are subject to pricing in the local markets
where the production occurs. It is customary that such products are priced
based
on local or regional supply and demand factors. California heavy crude sells
at
a discount to WTI, the U.S. benchmark crude oil, primarily due to the additional
cost to refine gasoline or light product out of a barrel of heavy crude.
Our
Utah light crude also is currently priced at $2.00 below WTI. Natural gas
field
prices are normally priced off of Henry Hub NYMEX price, the benchmark for
U.S.
natural gas. While we attempt to contract for the best possible price in
each of
our producing locations, there is no assurance that past price differentials
will continue into the future. Numerous factors may influence local pricing,
such as refinery capacity, particularly for black wax crude, pipeline capacity
and specifications, upsets in the mid-stream or downstream sectors of the
industry, trade restrictions, governmental regulations, etc. We may be adversely
impacted by a widening differential on the products sold.
Market
conditions or operational impediments may hinder our access to crude oil
and
natural gas markets or delay our production. Market
conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas
markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand
for
and supply of oil and natural gas and the proximity of reserves to pipelines
and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines,
processing facilities and refineries owned and operated by third parties.
Our
failure to obtain such services on acceptable terms could materially harm
our
business. We may be required to shut in wells for a lack of a market or because
of inadequacy or unavailability of natural gas pipeline, gathering system
capacity, processing facilities or refineries. If that were to occur, then
we
would be unable to realize revenue from those wells until arrangements were
made
to deliver the production to market. See firm transportation summary schedule
at
Item 1 Business.
Factors
that can cause price volatility for crude oil and natural gas
include:
| · |
availability
and capacity of refineries;
|
| · |
availability
of gathering systems with sufficient capacity to handle local
production;
|
| · |
seasonal
fluctuations in local demand for
production;
|
| · |
local
and national gas storage capacity;
|
| · |
interstate
pipeline capacity; and
|
| · |
availability
and cost of gas transportation facilities.
|
Brundage
Canyon crude oil production, which is approximately 40 degree API gravity,
is
sold under contract at WTI less a fixed differential approximating $2.00
per
barrel. This contract expires on September 30, 2006. Any new contract will
be
negotiated based on market prices. We believe the differential has widened
by
several dollars per barrel. The majority of this crude oil, while light,
is a
“paraffinic” crude, and can be processed efficiently by only a limited number
of stranded inland refineries. The production of this type crude is
increasing regionally and beginning to strain the capacity of these refineries.
Other new crude sources from the region are pressuring pricing. If these
refineries limit the volumes of this parraffinic crude oil they are willing
to
process, it could impact the marketability of this type of crude which, for
Berry, represents approximately 3,500 Bbl/D of production or approximately
15%
of total current production. We are investigating the market opportunities
for
this crude oil. If market prices continue to deteriorate,
we may
allocate capital expenditures to projects which produce natural gas and crude
oils with lower paraffinic content until the refinery constraint is
resolved.
We
may be subject to the risk of adding additional steam generation equipment
if
the electrical market deteriorates significantly.
We may
be subject to the risk of adding additional steam generation equipment if
the
electrical market deteriorates significantly. We are dependent on several
cogeneration facilities that provide over half of our steam requirement.
These
facilities are dependent on reasonable electrical contracts. If, for any
reason,
we were unable to enter into an electrical contract or were to lose an existing
contract, we may not be able to supply 100% of the steam requirements necessary
to maximize production from our heavy oil assets. An additional investment
in
various steam sources may be necessary to replace such steam, and there may
be
risks and delays in being able to install conventional steam equipment due
to
permitting requirements. The financial cost and timing of such investment
may
adversely affect our production, capital outlays and cash provided by operating
activities. We
have
electricity contracts covering most of our electricity generation which
contracts expire in 2009.
A
shortage of natural gas in California could adversely affect our business.
We
may be
subject to the risks associated with a shortage of natural gas and/or the
transportation of natural gas into and within California. We are highly
dependent on sufficient volumes of natural gas that we use for fuel in
generating steam in our heavy oil operations in California. If the required
volume of natural gas for use in our operations were to be unavailable or
too
highly priced to produce heavy oil economically, our production could be
adversely impacted. The
Company has firm transportation to move 12,000 MMBtu/D on the Kern River
Pipeline from the Rocky Mountains to Kern County, CA. This volume is
approximately one-third of the Company’s current requirement.
Our
use of oil and gas price hedging contracts involves credit risk and may limit
future revenues from price increases and result in significant fluctuations
in
net income.
We use
hedging transactions with respect to a portion of our oil and gas production
to
achieve more predictable cash flow and to reduce our exposure to a significant
decline in the price of crude oil. While the use of hedging transactions
limits
the downside risk of price declines, their use may also limit future revenues
from price increases. Hedging transactions also involve the risk that the
counterparty may be unable to satisfy its obligations. The Company utilizes
several counterparties for its hedging contracts.
Our
future success depends on our ability to find, develop and acquire oil and
gas
reserves. To
maintain production levels, we must locate and develop or acquire new oil
and
gas reserves to replace those depleted by production. Without successful
exploration, exploitation or acquisition activities, our reserves, production
and revenues will decline. We may not be able to find and develop or acquire
additional reserves at an acceptable cost. In addition, substantial capital
is
required to replace and grow reserves. If lower oil and gas prices or operating
difficulties result in our cash flow from operations being less than expected
or
limit our ability to borrow under credit arrangements, we may be unable to
expend the capital necessary to locate and develop or acquire new oil and
gas
reserves.
Actual
quantities of recoverable oil and gas reserves and future cash flows from
those
reserves ,
future production, oil and gas prices, revenues, taxes, development expenditures
and operating expenses most likely will vary from
estimates. Estimating
accumulations of oil and gas is complex. The process relies on interpretations
of available geologic, geophysical, engineering and production data. The
extent,
quality and reliability of this data can vary. The process also requires
certain
economic assumptions, such as oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds, some of
which
are mandated by the SEC. The accuracy of a reserve estimate is a function
of:
| · |
quality
and quantity of available data;
|
| · |
interpretation
of that data; and
|
| · |
accuracy
of various mandated economic
assumptions.
|
Any
significant variance could materially affect the quantities and present value
of
our reserves. In addition, we may adjust estimates of proved reserves to
reflect
production history, results of development and exploration and prevailing
oil
and gas prices.
In
accordance with SEC requirements, we base the estimated discounted future
net
cash flows from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the
prices
and costs as of the date of the estimate.
If
oil or gas prices decrease, we may be required to take writedowns.
We
may be
required to writedown the carrying value of our oil and gas properties when
oil
or gas prices are low, including basis differentials, or there are substantial
downward adjustments to our estimated proved reserves, increases in estimates
of
development costs or deterioration in exploration or production results.
We
capitalize costs to acquire, find and develop our oil and gas properties
under
the successful efforts accounting method. If net capitalized costs of our
oil
and gas properties exceed fair value, we must charge the amount of the excess
to
earnings. We review the carrying value of our properties annually and at
any
time when events or circumstances indicate a review is necessary, based on
prices in effect as of the end of the reporting period. The carrying value
of
oil and gas properties is computed on a field-by-field basis. Once incurred,
a
writedown of oil and gas properties is not reversible at a later date even
if
oil or gas prices increase. See Item 7A Quantitative and Qualitative Disclosures
About Market Risk for the Company’s hedge position on February 10,
2006.
Competitive
industry conditions may negatively affect our ability to conduct operations.
Competition
in the oil and gas industry is intense, particularly with respect to the
acquisition of producing properties and proved undeveloped acreage. Major
and
independent oil and gas companies actively bid for desirable oil and gas
properties, as well as for the equipment and labor required to operate and
develop their properties. Many of our competitors have financial resources
that
are substantially greater, which may adversely affect our ability to compete
within the industry.
Drilling
is a high-risk activity. Our
future success will partly depend on the success of our drilling program.
In
addition to the numerous operating risks described in more detail below,
these
drilling activities involve the risk that no commercially productive oil
or gas
reservoirs will be discovered. In addition, we are often uncertain as to
the
future cost or timing of drilling, completing and producing wells. Furthermore,
drilling operations may be curtailed, delayed or canceled as a result of
a
variety of factors, including:
| · |
obtaining
government and tribal required
permits;
|
| · |
unexpected
drilling conditions;
|
| · |
pressure
or irregularities in formations;
|
| · |
equipment
failures or accidents;
|
| · |
adverse
weather conditions;
|
| · |
compliance
with governmental or landowner requirements;
and
|
| · |
shortages
or delays in the availability of drilling rigs and the delivery
of
equipment and/or services.
|
The
oil and gas business involves many operating risks that can cause substantial
losses; insurance may not protect us against all of these risks. These risks
include:
| · |
fires;
|
| · |
explosions;
|
| · |
blow-outs;
|
| · |
uncontrollable
flows of oil, gas, formation water or drilling
fluids;
|
| · |
natural
disasters;
|
| · |
pipe
or cement failures;
|
| · |
casing
collapses;
|
| · |
embedded
oilfield drilling and service
tools;
|
| · |
abnormally
pressured formations;
|
| · |
major
equipment failures, including cogeneration facilities;
and
|
| · |
environmental
hazards such as oil spills, natural gas leaks, pipeline ruptures
and
discharges of toxic gases.
|
If
any of
these events occur, we could incur substantial losses as a result
of:
| · |
injury
or loss of life;
|
| · |
severe
damage or destruction of property, natural resources and
equipment;
|
| · |
pollution
and other environmental damage;
|
| · |
investigatory
and clean-up responsibilities;
|
| · |
regulatory
investigation and penalties;
|
| · |
suspension
of operations; and
|
| · |
repairs
to resume operations.
|
If
we
experience any of these problems, our ability to conduct operations could
be
adversely affected. If a significant accident or other event occurs and is
not
fully covered by insurance, it could adversely affect us. In accordance with
customary industry practices, we maintain insurance coverage against some,
but
not all, potential losses in order to protect against the risks we face.
We do
not carry business interruption insurance. We may elect not to carry insurance
if our Management believes that the cost of available insurance is excessive
relative to the risks presented. In addition, we cannot insure fully against
pollution and environmental risks. The occurrence of an event not fully covered
by insurance could have a material adverse effect on our financial condition
and
results of operations. While we intend to obtain and maintain appropriate
insurance coverage for these risks, there can be no assurance that our
operations will not expose us to liabilities exceeding such insurance coverage
or to liabilities not covered by insurance.
We
are subject to complex federal, state, local and other laws and regulations
that
could adversely affect the cost, manner or feasibility of doing
business.
Our
development, exploration, production and marketing operations are regulated
extensively at the federal, state and local levels. In addition, a portion
of
our leases in the Uinta Basin are, and some of our future leases may be,
regulated by Native American tribes. Environmental and other governmental
laws
and regulations have increased the costs to plan, design, drill, install,
operate and abandon oil and natural gas wells. Under these laws and regulations,
we could also be liable for personal injuries, property damage and other
damages. Failure to comply with these laws and regulations may result in
the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Moreover, public interest in environmental
protection has increased in recent years, and environmental organizations
oppose
certain drilling projects and/or access to prospective lands.
Part
of
the regulatory environment in which we operate includes, in some cases, federal
requirements for obtaining environmental assessments, environmental impact
studies and/or plans of development before commencing exploration and production
activities. In addition, our activities are subject to the regulation by
oil and
natural gas-producing states and one Native American tribe of conservation
practices and protection of correlative rights. These regulations affect
our
operations and limit the quantity of oil and natural gas we may produce and
sell. A major risk inherent in our drilling plans is the need to obtain drilling
permits from state, local and Native American tribal authorities. Delays
in
obtaining regulatory approvals or drilling permits, the failure to obtain
a
drilling permit for a well or the receipt of a permit with unreasonable
conditions or costs could have a negative effect on our ability to explore
on or
develop its properties. Additionally, the oil and natural gas regulatory
environment could change in ways that might substantially increase the financial
and managerial costs to comply with the requirements of these laws and
regulations and, consequently, adversely affect our profitability.
Property
acquisitions are a component of our growth strategy, and our failure to complete
future acquisitions successfully could reduce our earnings and slow our
growth.
Our
business strategy has emphasized growth through strategic acquisitions, but
we
may not be able to continue to identify properties for acquisition or we
may not
be able to make acquisitions on terms that we consider economically acceptable.
There is intense competition for acquisition opportunities in our industry.
Competition for acquisitions may increase the cost of, or cause us to refrain
from, completing acquisitions. Our strategy of completing acquisitions is
dependent upon, among other things, our ability to obtain debt and equity
financing and, in some cases, regulatory approvals. If we are unable to achieve
strategic acquisitions, our growth may be impaired, thus impacting earnings,
cash from operations and reserves.
Acquisitions
are subject to the uncertainties of evaluating recoverable reserves and
potential liabilities. Our
recent growth is due in part to acquisitions of producing properties, and
we
expect acquisitions will continue to contribute to our future growth. Successful
acquisitions require an assessment of a number of factors, many of which
are
beyond our control. These factors include recoverable reserves, exploration
potential, future oil and natural gas prices, operating costs, production
taxes
and potential environmental and other liabilities. Such assessments are inexact
and their accuracy is inherently uncertain. In connection with our assessments,
we perform a review of the acquired properties, which we believe is generally
consistent with industry practices. However, such a review will not reveal
all
existing or potential problems. In addition, our review may not allow us
to
become sufficiently familiar with the properties, and we do not always discover
structural, subsurface and environmental problems that may exist or arise.
Our
review prior to signing a definitive purchase agreement may be even more
limited.
We
generally are not entitled to contractual indemnification for preclosing
liabilities, including environmental liabilities, on acquisitions. Often,
we
acquire interests in properties on an "as is" basis with limited remedies
for
breaches of representations and warranties. If material breaches are discovered
by us prior to closing, we could require adjustments to the purchase price
or if
the claims are significant, we or the seller may have a right to terminate
the
agreement. We could also fail to discover breaches or defects prior to closing
and incur significant unknown liabilities, including environmental liabilities,
or experience losses due to title defects, for which we would have limited
or no
contractual remedies or insurance coverage.
There
are risks in acquiring producing properties, including difficulties in
integrating acquired properties into our business, additional liabilities
and
expenses associated with acquired properties, diversion of Management attention,
and costs of increased scope, geographic diversity and complexity of our
operations.
Increasing our reserve base through acquisitions is an important part of
our
business strategy. Our failure to integrate acquired businesses successfully
into our existing business, or the expense incurred in consummating future
acquisitions, could result in our incurring unanticipated expenses and losses.
In addition, we may have to assume cleanup or reclamation obligations or
other
unanticipated liabilities in connection with these acquisitions. The scope
and
cost of these obligations may ultimately be materially greater than estimated
at
the time of the acquisition.
In
connection with future acquisitions, the process of integrating acquired
operations into our existing operations may result in unforeseen operating
difficulties and may require significant Management attention and financial
resources that would otherwise be available for the ongoing development or
expansion of existing operations
Possible
future acquisitions could result in our incurring additional debt, contingent
liabilities and expenses, all of which could have a material adverse effect
on
our financial condition and operating results.
The
loss of key personnel could adversely affect our business.
We
depend
to a large extent on the efforts and continued employment of our executive
Management team and other key personnel. The loss of the services of these
or
other key personnel could adversely affect our business, and we do not maintain
key man insurance on the lives of any of these persons. Our drilling success
and
the success of other activities integral to our operations will depend, in
part,
on our ability to attract and retain experienced geologists, engineers, landmen
and other professionals. Competition for many of these professionals is intense.
If we cannot retain our technical personnel or attract additional experienced
technical personnel, our ability to compete could be harmed.
We
have limited control over the activities on properties that we do not operate.
Although
we operate most of the properties in which we have an interest, other companies
operate some of the properties. We have limited ability to influence or control
the operation or future development of these nonoperated properties or the
amount of capital expenditures that we are required to fund their operation.
Our
dependence on the operator and other working interest owners for these projects
and our limited ability to influence or control the operation and future
development of these properties could have a material adverse effect on the
realization of our targeted returns or lead to unexpected future costs.
We
may not adhere to our proposed drilling schedule. Our
final
determination of whether to drill any scheduled or budgeted wells will depend
on
a number of factors, including:
| · |
results
of our exploration efforts and the acquisition, review and analysis
of our
seismic data, if any;
|
| · |
availability
of sufficient capital resources to us and any other participants
for the
drilling of the prospects;
|
| · |
approval
of the prospects by other participants after additional data has
been
compiled;
|
| · |
economic
and industry conditions at the time of drilling, including prevailing
and
anticipated prices for oil and natural gas and the availability
and prices
of drilling rigs and crews; and
|
| · |
availability
of leases, license options, farm-outs, other rights to explore
and permits
on reasonable terms for the
prospects.
|
Although
we have identified or budgeted for numerous drilling prospects, we may not
be
able to lease or drill those prospects within our expected time frame, or
at
all. In addition, our drilling schedule may vary from our expectations because
of future uncertainties and rig availability and access to our drilling
locations utilizing available roads. As of December 31, 2005, the Company
owns
two drilling rigs and has additional one-year contract commitments on another
two drilling rigs. See Note 10 to the financial statements.
We
may incur losses as a result of title deficiencies. We
purchase working and revenue interests in the oil and natural gas leasehold
interests upon which we will perform our exploration activities from third
parties or directly from the mineral fee owners. The existence of a material
title deficiency can render a lease worthless and can adversely affect our
results of operations and financial condition. Title insurance covering mineral
leaseholds is not generally available and, often, we forego the expense of
retaining lawyers to examine the title to the mineral interest to be placed
under lease or already placed under lease until the drilling block is assembled
and ready to be drilled. As is customary in our industry, we rely upon the
judgment of oil and natural gas lease brokers or independent landmen who
perform
the field work in examining records in the appropriate governmental offices
and
abstract facilities before attempting to acquire or place under lease a specific
mineral interest. We, in some cases, perform curative work to correct
deficiencies in the marketability of the title to us. The work might include
obtaining affidavits of heirship or causing an estate to be administered.
In
cases involving more serious title problems, the amount paid for affected
oil
and natural gas leases can be generally lost, and the target area can become
undrillable.
The
future of the electricity market in California is uncertain.
We
utilize cogeneration plants in California to generate lower cost steam compared
to conventional steam generation methods. Electricity produced by our
cogeneration plants is sold to utilities and the steam costs are allocated
to
our oil and gas operations. While we have electricity sales contracts in
place
with the utilities that are currently scheduled to terminate in 2009, legal
and
regulatory decisions, especially related to the pricing of electricity under
the
contracts, can adversely affect the economics of our cogeneration facilities
and
thereby, the cost of steam for use in our oil and gas operations.
Estimates
may differ from actual. The
preparation of financial statements in conformity with accounting principles
generally accepted in the U.S. requires Management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
related disclosure of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenues and expenses during
the reporting period. Certain accounting policies involve judgments and
uncertainties to such an extent that there is reasonable likelihood that
materially different amounts could have been reported under different
conditions, or if different assumptions had been used. Actual results may
differ
from these estimates and assumptions used in preparation of its financial
statements. Significant estimates with regard to these financial statements
include the estimate of proved oil and gas reserve quantities, the related
present value of estimated future net cash flows therefrom, the costs to
develop
and abandon oil and gas properties, the valuation of derivative positions
and
stock-based compensation valuation.
None.
Information
required by Item 2 Properties is included under Item 1 Business.
While
the
Company is, from time to time, a party to certain lawsuits in the ordinary
course of business, the Company does not believe any of such existing lawsuits
will have a material adverse effect on the Company's operations, financial
condition, or liquidity.
No
matters were submitted to a vote of security holders during the most recently
ended fiscal quarter.
Executive
Officers of the Registrant. Listed
below are the names, ages (as of December 31, 2005) and positions of the
executive officers of Berry and their business experience during at least
the
past five years. All officers of the Company are appointed in May of each
year
at an organizational meeting of the Board of Directors. There are no family
relationships between any of the executive officers and members of the Board
of
Directors.
ROBERT
F.
HEINEMANN, 52, has been President and Chief Executive Officer since June
2004.
Mr. Heinemann was Chairman of the Board and interim President and Chief
Executive Officer from April 2004 to June 2004. From December 2003 to March
2004, Mr. Heinemann was the director designated to serve as the presiding
director at executive sessions of the Board in the absences of the Chairman
and
to act as liaison between the independent directors and the CEO. Mr. Heinemann
joined the Company’s Board in March of 2003. From 2000 until 2002, Mr. Heinemann
served as the Senior Vice President and Chief Technology Officer of Halliburton
Company and as the Chairman of the Halliburton Technology Advisory Committee.
He
was previously with Mobil Oil Corporation (Mobil) where he served in a variety
of positions for Mobil and its various affiliate companies in the energy
and
technical fields from 1981 to 1999, with his last responsibilities as Vice
President of Mobil Technology Company and General Manager of the Mobil
Exploration and Producing Technical Center.
RALPH
J.
GOEHRING, 49, has been Executive Vice President and Chief Financial Officer
since June 2004. Mr. Goehring was Senior Vice President from April 1997 to
June
2004, and has been Chief Financial Officer since March 1992 and was Manager
of
Taxation from September 1987 until March 1992. Mr. Goehring is also an Assistant
Secretary for the Company.
MICHAEL
DUGINSKI, 39, has been Executive Vice President of Corporate Development
and
California since October 2005. Mr. Duginski was Senior Vice President of
Corporate Development from June 2004 through October 2005 and was Vice President
of Corporate Development from February 2002 through June 2004. Mr. Duginski,
a
mechanical engineer, was previously with Texaco, Inc. from 1988 to 2002 where
his positions included Director of New Business Development, Production Manager
and Gas and Power Operations Manager. Mr. Duginski is also an Assistant
Secretary for the Company.
LOGAN
MAGRUDER, 49, has been Executive Vice President of the Rocky Mountains and
Mid-Continent region since October 2005. Mr. Magruder was Senior Vice President
of the Rocky Mountain and Mid-Continent region from June 2004 through October
2005 and was Vice President of the Rocky Mountain and Mid-Continent region
from
August 2003 through June 2004. Mr. Magruder, a petroleum engineer, was a
consultant for the Company from February 2003 through August 2003. Mr. Magruder
was previously Vice President of U.S. Operations for Calpine Natural Gas
Company
from 2001 to 2003. Prior to Calpine, Mr. Magruder was employed by Barrett
Resources as Vice President of Engineering and Operations from 1996 to 2001.
DAN
ANDERSON, 43, has been Vice President of Rocky Mountains and Mid-Continent
Production since October 2005. Mr. Anderson was Rocky Mountain and Mid-Continent
Manager of Engineering from August 2003 through October 2005. Mr. Anderson
was
previously a Senior Staff Petroleum Engineer with Williams Production RMT
from
August 2001 through August 2003. He previously was a Senior Staff Engineer
with
Barrett Resources from October 2000 through August 2001.
GEORGE
T.
CRAWFORD, 45, has been Vice President of California Production since October
2005. Mr. Crawford was Vice President of Production from December 2000 through
October 2005 and was Manager of Production from January 1999 to December
2000.
Mr. Crawford, a petroleum engineer, was previously the Production Engineering
Supervisor for Atlantic Richfield Corp. (ARCO) from 1989 to 1998 in numerous
engineering and operational assignments including Production Engineering
Supervisor, Planning and Evaluation Consultant and Operations
Superintendent.
BRUCE
S.
KELSO, 50, has been Vice President of Rocky Mountains and Mid-Continent
Exploration since October 2005. Mr. Kelso was Rocky Mountain and Mid-Continent
Exploration Manager from August 2003 through October 2005. Mr. Kelso, a
petroleum geologist, was previously a Senior Staff Geologist assigned to
Rocky
Mountain assets with Williams Production RMT, from January 2002 through August
2003. He previously was the Vice President of Exploration and Development
at
Redstone Resources, Inc. from 2000 to 2001.
BRIAN
L.
REHKOPF, 58, has been Vice President of Technology since October 2005. Mr.
Rehkopf was Vice President of Engineering from March 2000 through October
2005
and was Manager of Engineering from September 1997 to March 2000. Mr. Rehkopf,
a
registered petroleum engineer, joined the Company’s engineering department in
June 1997 and was previously a Vice President and Asset Manager with ARCO
since
1992 and an Operations Engineering Supervisor from 1988 to 1992. Mr. Rehkopf
is
also an Assistant Secretary for the Company.
SHAWN
M.
CANADAY, 30, has been Treasurer since December 2004 and was Senior Financial
Analyst from November 2003 until December 2004. Mr. Canaday has worked in
the
oil and gas industry since 1998 in various finance functions at ChevronTexaco
and in public accounting. Mr. Canaday is also an Assistant Secretary for
the
Company.
DONALD
A.
DALE, 59, has been Controller since December 1985.
KENNETH
A. OLSON, 50, has been Corporate Secretary since December 1985 and was Treasurer
from August 1988 until December 2004.
PART
II
Shares
of
Class A Common Stock (Common Stock) and Class B Stock, referred to collectively
as the "Capital Stock," are each entitled to one vote and 95% of one vote,
respectively. Each share of Class B Stock is entitled to a $1.00 per share
preference in the event of liquidation or dissolution. Further, each share
of
Class B Stock is convertible into one share of Common Stock at the option
of the
holder.
In
November 1999, the Company adopted a Shareholder Rights Agreement and declared
a
dividend distribution of one such Right for each outstanding share of Capital
Stock on December 8, 1999. Each share of Capital Stock issued after December
8,
1999 includes one Right. The Rights expire on December 8, 2009. See Note
7 to
the financial statements.
Berry's
Class A Common Stock is listed on the New York Stock Exchange (NYSE) under
the
symbol BRY. The Class B Stock is not publicly traded. The market data and
dividends for 2005 and 2004 are shown below:
|
|
|
2005
|
|
2004
|
|
||||||||||||||
|
|
|
Price
Range
|
|
Dividends
|
|
Price
Range
|
|
Dividends
|
|
||||||||||
|
|
|
High
|
|
Low
|
|
Per
Share
|
|
High
|
|
Low
|
|
Per
Share
|
|
||||||
|
First
Quarter
|
|
$
|
66.09
|
$
|
43.85
|
$
|
.12
|
|
$
|
27.30
|
|
$
|
18.25
|
|
$
|
0.11
|
|
||
|
Second
Quarter
|
|
|
54.95
|
40.78
|
.12
|
|
|
31.07
|
|
|
25.09
|
|
|
0.11
|
|
||||
|
Third
Quarter
|
|
|
67.00
|
52.30
|
.23
|
|
|
38.44
|
|
|
27.73
|
|
|
0.18
|
|
||||
|
Fourth
Quarter
|
|
|
68.66
|
52.30
|
.13
|
|
|
50.58
|
|
|
35.16
|
|
|
0.12
|
|
||||
|
Total
Dividend Paid
|
$
|
.60
|
$
|
.52
|
|||||||||||||||
|
|
|
February
10, 2006
|
|
December
31, 2005
|
|
December
31, 2004
|
|
|||
|
Berry’s
Common Stock closing price per share as reported on NYSE Composite
Transaction Reporting System
|
|
$
|
68.90
|
|
$
|
57.20
|
$
|
47.70
|
|
|
The
number of holders of record of the Company's Common Stock was 605 as of February
10, 2006. There was one Class B Shareholder of record as of February 10,
2006.
Dividends.
The
Company paid a special dividend of $.10 per share on September 29, 2005 and
increased its regular quarterly dividend by 8%, from $.12 to $.13 per share
beginning with the September 29, 2005 dividend. The Company's regular annual
dividend is currently $.52 per share, payable quarterly in March, June,
September and December. The Company paid a special dividend of $.06 per share
on
September 29, 2004 and increased its regular quarterly dividend by 9%, from
$.11
to $.12 per share beginning with the September 2004 dividend.
Since
Berry Petroleum Company's formation in 1985 through December 31, 2005, the
Company has paid dividends on its Common Stock for 65 consecutive quarters
and
previous to that for eight consecutive semi-annual periods. The Company intends
to continue the payment of dividends, although future dividend payments will
depend upon the Company's level of earnings, operating cash flow, capital
commitments, financial covenants and other relevant factors. Dividend payments
are limited by covenants in the Company's credit facility to the greater
of $20
million or 75% of net income.
As
of
December 31, 2005, dividends declared on 3,984,080 shares of certain Common
Stock are restricted, whereby 37.5% of the dividends declared on these shares
are paid by the Company to the surviving member of a group of individuals,
the B
group, for as long as this remaining member shall live.
Equity
Compensation Plan Information
|
|
|
Number
of securities to be
|
|
|
|
|
|
|
|
issued
upon exercise of
|
|
Weighted
average exercise
|
|
Number
of securities
|
|
|
|
outstanding
options, warrants
|
|
price
of outstanding options,
|
|
remaining
available for future
|
|
Plan
category
|
|
and
rights
|
|
warrants
and rights
|
|
issuance
|
|
Equity
compensation plans approved by security holders
|
|
1,625,763
|
$33.52
|
1,080,187
|
||
|
|
|
|||||
|
Equity
compensation plans not approved by security holders
|
|
-
|
-
|
-
|
In
June
2005, the Company announced that its Board of Directors authorized a share
repurchase program for up to an aggregate of $50 million of the Company's
outstanding Class A Common Stock. Through December 31, 2005, the Company
repurchased 108,900 shares for approximately $6.3 million, which increased
diluted earnings by $.01 per share.
In
December 2005, the Company adopted a plan under Rule 10b5-1 of the Securities
Exchange Act of 1934 to facilitate the repurchase of its shares of common
stock.
Rule 10b5-1 allows a company to purchase its shares at times when it would
not
normally be in the market due to possession of nonpublic information, such
as
the time immediately preceding its quarterly earnings releases. In addition
to
share repurchases by the Rule 10b5-1 plan, Berry expects to continue repurchases
in the open market from time to time during its normal trading windows. This
10b5-1 plan is authorized under, and is administered consistent with, the
Company's $50 million share repurchase program. All repurchases of common
stock
are made in compliance with regulations set forth by the SEC and are subject
to
market conditions, applicable legal requirements and other factors.
This
program does not obligate the Company to acquire any particular amount of
common
stock and the plan may be suspended at any time at the Company's
discretion.
Issuer
Purchases of Equity Securities
|
Period
|
(a)
Total number of shares purchased
|
(b)
Average price paid per share
|
(c)
Total number of shares purchased as part of publicly announced
plans or
programs
|
(d)
Maximum number (or approximate dollar value) of shares that may
yet be
purchased under the plans or programs
|
||||
|
Third
Quarter 2005
|
43,900
|
$58.48
|
|
43,900
|
|
$47,433,000
|
||
|
November
2005
|
16,300
|
57.25
|
|
16,300
|
|
46,500,000
|
||
|
December
2005
|
48,700
|
57.80
|
|
48,700
|
|
43,684,500
|
||
|
Total
|
|
108,900
|
|
$57.99
|
|
108,900
|
|
$43,684,500
|
The
following table sets forth certain financial information with respect to
the
Company and is qualified in its entirety by reference to the historical
financial statements and notes thereto of the Company included in Item 8
Financial Statements and Supplementary Data. The statement of income and
balance
sheet data included in this table for each of the five years in the period
ended
December 31, 2005 were derived from the audited financial statements and
the
accompanying notes to those financial statements (in thousands, except per
share, per BOE and % data).
|
|
|
2005
|
|
2004
(3)
|
|
2003
(3)
|
|
2002
(1) (3)
|
|
2001
(1) (3)
|
|
|||||
|
Audited
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Statement
of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Sales
of oil and gas
|
|
$
|
349,691
|
|
$
|
226,876
|
|
$
|
135,848
|
|
$
|
102,026
|
|
$
|
100,146
|
|
|
Sales
of electricity
|
|
|
55,230
|
|
|
47,644
|
|
|
44,200
|
|
|
27,691
|
|
|
35,133
|
|
|
Operating
costs - oil and gas production
|
|
|
99,066
|
|
|
73,838
|
|
|
57,830
|
|
|
41,108
|
34,605
|
|
||
|
Operating
costs - electricity generation
|
|
|
55,086
|
|
|
46,191
|
|
|
42,351
|
|
|
26,747
|
|
|
36,890
|
|
|
Production
taxes
|
11,506
|
6,431
|
3,097
|
2,907
|
2,479
|
|||||||||||
|
General
and administrative expenses (G&A)
|
|
|
21,396
|
|
|
22,504
|
|
|
14,495
|
|
|
10,417
|
|
|
9.748
|
|
|
Depreciation,
depletion & amortization (DD&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas production
|
|
|
38,150
|
|
|
29,752
|
|
|
17,258
|
|
|
13,388
|
|
|
13,225
|
|
|
Electricity
generation
|
|
|
3,260
|
|
|
3,490
|
|
|
3,256
|
|
|
3,064
|
|
|
3,295
|
|
|
Net
income
|
|
|
112,356
|
|
|
69,187
|
|
|
32,363
|
|
|
29,210
|
|
|
20,985
|
|
|
Basic
net income per share
|
|
|
5.10
|
|
|
3.16
|
|
|
1.49
|
|
|
1.34
|
|
|
0.96
|
|
|
Diluted
net income per share
|
|
|
5.00
|
|
|
3.08
|
|
|
1.47
|
|
|
1.33
|
|
|
0.95
|
|
|
Weighted
average number of shares outstanding (basic)
|
|
|
22,041
|
|
|
21,894
|
|
|
21,772
|
|
|
21,741
|
|
|
21,973
|
|
|
Weighted
average number of shares outstanding (diluted)
|
|
|
22,490
|
|
|
22,470
|
|
|
22,031
|
|
|
21,902
|
|
|
22,162
|
|
|
Balance
Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working
capital
|
|
$
|
(54,757
|
)
|
$
|
(3,840
|
)
|
$
|
(3,540
|
)
|
$
|
(2,892
|
)
|
$
|
6,314
|
|
|
Total
assets
|
|
|
635,051
|
|
|
412,104
|
|
|
340,377
|
|
|
259,325
|
|
|
238,779
|
|
|
Long-term
debt
|
|
|
75,000
|
|
|
28,000
|
|
|
50,000
|
|
|
15,000
|
|
|
25,000
|
|
|
Shareholders'
equity
|
|
|
334,210
|
|
|
263,086
|
|
|
197,338
|
|
|
172,774
|
|
|
153,590
|
|
|
Cash
dividends per share
|
|
|
0.60
|
|
|
0.52
|
|
|
0.47
|
|
|
0.40
|
|
|
0.40
|
|
|
Operating
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flow from operations
|
|
|
187,780
|
|
|
124,613
|
|
|
64,825
|
|
|
57,895
|
|
|
35,433
|
|
|
Exploration
and development of oil and gas properties
|
|
|
118,718
|
|
|
71,556
|
|
|
41,061
|
|
|
30,163
|
|
|
14,776
|
|
|
Property/facility
acquisitions
|
|
|
112,249
|
|
|
2,845
|
|
|
48,579
|
|
|
5,880
|
|
|
2,273
|
|
|
Additions
to vehicles, drilling rigs and other fixed assets
|
|
|
11,762
|
669
|
494
|
469
|
119
|
|
||||||||
|
Unaudited
Operating Data
|
|
|
||||||||||||||
|
Oil
and gas producing operations (per BOE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
47.01
|
|
$
|
33.64
|
|
$
|
24.48
|
|
$
|
20.11
|
|
$
|
19.63
|
|
|
Average
sales price after hedging
|
|
|
41.62
|
|
|
30.32
|
|
|
22.52
|
|
|
19.39
|
|
|
19.79
|
|
|
Average
operating costs - oil and gas production
|
|
|
11.79
|
|
|
10.09
|
|
|
9.57
|
|
|
7.83
|
|
|
6.86
|
|
|
Production
taxes
|
1.37
|
.86
|
.51
|
.55
|
.49
|
|||||||||||
|
G&A
|
|
|
2.55
|
|
|
2.99
|
|
|
2.40
|
|
|
1.98
|
|
|
1.93
|
|
|
DD&A
- oil and gas production
|
|
|
4.54
|
|
|
3.96
|
|
|
2.86
|
|
|
2.55
|
|
|
3.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
(MBOE)
|
|
|
8,401
|
|
|
7,517
|
|
|
6,040
|
|
|
5,251
|
|
|
5,044
|
|
|
Production
(MMWh)
|
|
|
741
|
|
|
776
|
|
|
767
|
|
|
748
|
|
|
483
|
|
|
Proved
Reserves Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
BOE
|
|
|
126,285
|
|
|
109,836
|
|
|
109,920
|
|
|
101,719
|
|
|
102,855
|
|
|
Standardized
measure (2)
|
|
$
|
1,251,380
|
|
$
|
686,748
|
|
$
|
528,220
|
|
$
|
449,857
|
|
$
|
278,453
|
|
|
Year-end
average BOE price for PV10 purposes
|
|
|
48.21
|
|
|
29.87
|
|
|
25.89
|
|
|
24.91
|
|
|
14.13
|
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return
on average shareholders' equity
|
|
|
37.63
|
%
|
|
31.06
|
%
|
|
17.50
|
%
|
|
17.90
|
%
|
|
14.00
|
%
|
|
Return
on average total assets
|
|
|
20.15
|
%
|
|
18.60
|
%
|
|
10.80
|
%
|
|
11.70
|
%
|
|
8.80
|
%
|
(1)
Information has been revised to reflect the Company's change in allocation
of
cogeneration costs to oil and gas operations. See Item 7 Management’s Discussion
and Analysis.
(2)
See Supplemental Information About Oil & Gas Producing
Activities.
(3)
Information has been revised to reflect the Company's change in allocation
of
technical labor and production taxes. See Note 2 to the financial
statements.
Corporate
Strategy.
Berry’s
mission is to increase shareholder value, primarily through increasing the
net
asset value and maximizing the cash flow and earnings of its assets. The
strategies to accomplish these goals include:
| · |
Growing
production and reserves from existing assets while managing
expenses
|
| · |
Acquiring
more light oil and natural gas assets with significant growth potential
in
the Rocky Mountain and Mid-Continent
region
|
| · |
Appraising
our exploitation and exploration projects in an expedient
manner
|
| · |
Investing
our capital in an efficient, disciplined manner to increase production
and
reserves
|
| · |
Utilizing
joint ventures with respected partners to enter new
basins
|
Notable
Items in 2005.
| · |
Achieved
record production which averaged 23,015 BOE/D, up 12% from
2004
|
| · |
Achieved
record cash from operating activities of $188 million, up 50% from
2004
|
| · |
Achieved
record net income of $112 million, up 62% from
2004
|
| · |
2005
developmental capital expenditures were $131 million, up 82% from
2004
|
| · |
Acquired
and integrated the eastern Colorado Niobrara natural gas producing
assets
- acquisition cost of $105 million
|
| · |
Added
24.9 million BOE of reserves before production ending 2005 at 126.3
million BOE
|
| · |
Achieved
reserve replacement rate of 296%
|
| · |
Negotiated
new four-year crude oil sales contract for California heavy oil
production
|
| · |
Observed
positive results on Diatomite play and expanded
pilot
|
| · |
Placed
price collars on 10,000 barrels per day of future production from
2006
through 2009
|
| · |
Added
approximately 186,000 gross (46,000 net) acres in the North Dakota
Bakken
play
|
| · |
Added
approximately 624,000 gross (315,000 net) acres to Tri-State area
inventory
|
| · |
Increased
quarterly dividend to $.13 per share and paid special dividend
of $.10 per
share for total payout of $.60 per
share
|
| · |
Began
drilling to assess several prospects including Lake Canyon, Coyote
Flats
and Tri-State area
|
| · |
Increased
financial capacity by establishing a $500 million unsecured credit
facility
|
| · |
Initiated
a $50 million share buyback program
|
Acquisitions. On
January 27, 2005, we acquired certain interests in the Niobrara fields in
northeastern Colorado for approximately $105 million. At December 31, 2005
the
properties consist of approximately 127,000 gross (100,000 net) acres.
Production at acquisition was approximately 9 MMcf of natural gas per day,
with
estimated proved reserves of 87 Bcf. For the month of December 2005, production
averaged approximately 13,800 MMcf per day and reserves were 105 Bcf. The
acquisition included approximately 200 miles of a pipeline gathering system
and
gas compression facilities for delivery into interstate gas lines.
In
January 2005, we acquired a working interest in eastern Colorado, western
Kansas
and southwestern Nebraska, from an industry partner. Berry and its partner,
will
jointly explore and develop shallow Niobrara natural gas, Sharon Springs
shale
gas and deeper Pennsylvanian formation oil assets on the acreage. We paid
approximately $5 million for our working interest in the acreage and believe
the
potential of the Tri-State area can be exploited by using new drilling
techniques, with 3-D seismic technology, to assess structural complexity,
estimate potentially recoverable oil and gas and determine drilling locations.
In
2005,
we completed several transactions whereby we now have working interests in
186,000 gross acres (46,000 net) located in the Williston Basin in North
Dakota.
These lease acquisitions, totaling approximately $11 million, provide us
an
entry into the emerging Bakken oil play in the Williston Basin. The acreage
covers several contiguous blocks located primarily on the eastern flank of
the
Nesson Anticline. Development activity in the Middle Bakken play is generally
expanding to the area surrounding the Nesson Anticline.
In
October 2005, we purchased a 50% working interest in approximately 69,000
gross
undeveloped acres (24,000 net) in Colorado’s Phillips and Sedgwick Counties.
This additional Niobrara leasehold position is adjacent to and immediately
north
of Berry’s producing natural gas assets in Yuma County. We expect to begin
shooting a 3-D seismic survey and drilling the first delineation wells in
2006.
On
January 27, 2006, we announced an agreement with a private seller to acquire
a
50% working interest in natural gas assets in the Piceance Basin of western
Colorado for approximately $150 million in cash. Berry internally estimates
there are 26 billion cubic feet (Bcf) of proved reserves and has identified
over
600 drilling locations based on 10-acre development. We will be the operator
in
the 6,314 gross acres targeting gas in the Williams Fork section of the
Mesaverde formation. We increased the 2006 capital budget by an additional
$48
million to $208 million to develop this resource. There are two drilling
rigs
dedicated to this project, and we will ramp up our drilling activity to four
rigs by the end of the year along with complementary services and goods to
accelerate the development of this acquisition. Based on the productivity
of
this acreage and surrounding producing operations, we are seeking to add
additional drilling rigs to accelerate development. The transaction closed
on
February 28, 2006.
Capital
Expenditures. Excluding
any future acquisitions, in 2006 we plan to spend approximately $208 million.
These expenditures will be directed toward developing reserves, increasing
oil
and gas production and exploration opportunities. For 2006, Berry plans to
invest approximately $146 million, or 70%, in our Rocky Mountain and
Mid-Continent region assets, and $61 million, or 30%, in our California assets.
Approximately half the capital budget is focused on converting probable and
possible reserves into proved reserves and on our appraisal and exploratory
projects.
This
robust capital program allows Berry to continue its record activity levels
by
planning to drill 476 net wells and perform 55 well workover activities in
2006
versus approximately 188 wells and 140 well workovers in 2005. As a result,
we
are targeting production growth of 12% to average approximately 25,800 BOE
per
day, which includes the Piceance Basin acquisition, but before any other
acquisitions, and we plan to continue to actively appraise significant acreage
positions held for hydrocarbon potential. In 2006, we expect production to
be
approximately 70% heavy oil, 15% light oil and 15% natural gas and anticipate
funding our capital program from internally generated cash flow. Successes
may
also encourage the initiation of additional discretionary projects. We have
currently secured the necessary equipment and are meeting permit requirements
to
achieve the 2006 program.
Appraisal,
Evaluation and Exploitation Activity. Since
2003, we have been active in assembling significant acreage positions which
we
believe are highly prospective for finding and developing commercial quantities
of hydrocarbons. This chart depicts our prospective acreage by basin, all
of
which is in the Rocky Mountain and Mid-Continent region:
Rocky
Mountain and Mid-Continent
We
plan
to appraise five project areas in this region in 2006 for an estimated $23
million budgeted. These five projects are Lake Canyon, Coyote Flats, Big
Wash
Unit, Tri-State Area and the Bakken Play. We have interests in over one million
gross acres, including both productive and prospective, in the Rocky Mountain
and Mid-Continent region and the acreage in the five appraisal projects accounts
for about 80% of that total.
Uinta
Basin Projects
Lake
Canyon - Shallow: On January 13, 2006, we announced commercial success from
our
first two wells on this acreage. The Nielsen Marsing and Taylor Herrick wells
have tested production rates of 98 and 163 BOE/D, respectively, from the
same
Green River formation that is productive immediately east (approximately
3
miles) in our Brundage Canyon field. Initial performance from these discovery
wells suggests that expected reserves per well are on par with the Brundage
Canyon field (approximately 80,000 BOE gross) that is currently being developed
on 40-acre spacing. Current production from the Taylor Herrick well is not
at
full capacity as additional facilities are in the process of being installed.
Production from the Nielsen Marsing well is selectively limited to two of
five
completion intervals within the well and will be further optimized by March
2006
when natural gas facilities are completed. We are proceeding with another
four
wells on the eastern edge of this 169,000 acre block. If the results of these
wells are deemed satisfactory, Berry will expand the drilling program and
attempt to drill up to another 30 wells over approximately 20,000 acres.
The
focus will be to begin the methodical appraisal of a sizeable portion of
this
acreage block. Berry’s working interest in these wells will be either 75% or
56.25% depending on the participation of the land owner. The shallow zones
are
those above the Wasatch which is at approximately 6,500 feet.
Lake
Canyon - Deep: Berry’s industry partner recently reached total depth of 14,325
feet on its Mesaverde test and set casing to a depth of 11,539 feet. Testing
will focus on several Upper Price River and shallower Wasatch intervals where
analysis indicates gas potential; the deeper Mesaverde and Blackhawk intervals
did not warrant further evaluation. Berry will participate with its industry
partner to complete the testing and evaluation of the first deep well on
the
acreage once pipeline construction into the area is completed, which is
currently targeted by May 1, 2006. The second well is scheduled to begin
drilling in the fourth quarter of 2006.
Coyote
Flats: We will continue to test the viability of the Ferron gas development
and
Emery CBM pilot with additional drilling.
Big
Wash
Unit: We will test the shallow oil and deeper gas potential located about
two
miles southeast of Brundage Canyon.
Denver-Julesburg
Basin Projects
Tri-State
Area: We will be very active in testing the Niobrara gas potential located
in
the Tri-State area of Colorado, Kansas and Nebraska. We will participate
in 16
exploratory gas wells, drill 11 development wells and acquire additional
3D
seismic. Immediately to the north of our producing assets in Yuma County,
Colorado, we may drill up to 17 wells based on the acquisition of new seismic
data covering the northern acreage.
Williston
Basin Projects
Bakken
Play: In North Dakota, we intend to participate with up to a 15% working
interest in at least four horizontal oil wells to appraise the prospective
oil
formation.
California-Diatomite
In
2005,
oil production from the initial 14 well pilot (6 producers) averaged
approximately 135 Bbl/D.
Based on promising results from the pilot project, we began an expansion
of the
pilot with a 25 well program (15 producers) in the third quarter of 2005,
and
completed it in the fourth quarter. We continue to assess the long-term economic
and operating viability of the project as the early wells are an indication
of
future large-scale development. Results are in accordance with expectations.
We
are judiciously monitoring the steam to oil ratio (SOR) because we believe
achieving an SOR of 6 or less is the threshold for commerciality. SOR measures
how much steam is required for injection into the reservoir to produce one
barrel of oil. Estimated original oil in place ranges between 200 million
to 250
million barrels with targets of a minimum 25% recovery of original oil in
place.
In 2005, we booked 2.5 million BOE of reserves based on asset performance.
We
believe that the project continues to remain on track towards
commerciality.
In
2006,
we are expanding the commercial test of our diatomite resource by investing
approximately $25 million in a program that will add another 50 wells (31
producers, 16 steam injectors, and 3 service wells). Since completing our
expansion of the initial pilot in December 2005, we now have a total of 39
wells
(21 producers, 15 steam injectors, and 3 service wells) that we will be using
to
monitor reservoir performance. In addition to the drilling program, we will
add
significant facilities including steam generation equipment and will be
optimizing the pattern configuration and layout for the eventual full-field
development if commerciality is determined.
Development
Activity
Rocky
Mountain and Mid-Continent
Approximately
$93 million will be invested in this region, with $58 million targeting the
continued development drilling of the Green River formation at Brundage Canyon
to assist full development and will include a 20-acre spacing pilot. In
northeastern Colorado, $17 million will be invested to acquire additional
seismic data and drill 150 wells to further develop the Niobrara natural
gas
production from our producing assets.
California
Berry
will invest $37 million in its heavy oil properties, utilizing horizontal
well
and new steam-optimization technologies to maximize recovery from our legacy
assets. Development activity at our Poso Creek, Ethel D and Midway-Sunset
assets
will utilize improved application of steam flood technology to provide
production growth.
See
Item
1 Business for more information on Development Activity.
Obstacles
and Risks to Accomplishment of Strategies and Goals.
See Item
1A Other Factors Affecting the Company's Business and Financial Results for
a
detailed discussion of factors that affect our business, financial condition
and
results of operations.
Results
of Operations. Approximately
86% of Berry's revenues are generated through the sale of oil and natural
gas
production under either negotiated contracts or spot gas purchase contracts
at
market prices. Over 83% of these volumes are from oil production, and the
majority of those volumes are from heavy oil production in California. The
remaining 14% of Berry's revenues are derived from electricity sales from
cogeneration facilities which supply over half of Berry’s steam requirement for
use in its California thermal heavy oil operations. We have invested in these
facilities for the purpose of lowering our steam costs which are significant
in
the production of heavy crude oil.
Revenues.
Sales of
oil and gas were up 54% in 2005 compared to 2004 and up 157% from 2003. This
significant improvement was due to increases in both oil and gas prices and
production levels.
 |
Improvements
in production volume are due to acquisitions and sizable capital
investments. Improvement in prices during 2005 are due to a tighter
supply
and demand balance and the nervousness of the market about possible
supply
disruptions. The increase in oil prices contributed roughly two-thirds
of
the revenue increase and the increase in production volumes contributed
the other third. Approximately 84% of Berry’s oil and gas sales volumes in
2005 were crude oil, with 78% of the crude oil being heavy oil
produced in
California which was sold under a contract based on the higher
of WTI
minus a fixed differential or the average posted price plus a premium.
This contract ended on January 31, 2006. The contract allowed us
to
improve our California revenues over the posted price by approximately
$38
million and $13 million in 2005 and 2004, respectively.
On
November 21, 2005, we entered into a new crude oil sales contract
for our
California production for deliveries beginning February 1, 2006.
The per
barrel price, calculated on a monthly basis and blended across
the various
producing locations, is the higher of 1) the WTI NYMEX crude oil
price
less a fixed differential approximating $8.15, or 2) heavy oil
field
postings plus a premium of approximately $1.35. The initial term
of the
contract is for four years with a one-year renewal at our option.
The
agreement effectively eliminates our exposure to the risk of a
widening
WTI to California heavy crude price differential and allows us
to
effectively hedge our production based on WTI pricing similar to
the
previous contract. Initial deliveries under the contract are
approximately 15,000 net barrels per day or approximately two-thirds
of
Berry's total production.
|
Brundage
Canyon crude oil production, which is approximately 40 degree API gravity,
is
sold under contract at WTI less a fixed differential approximating $2.00
per
barrel. This contract expires on September 30, 2006. Any new contract will
be
negotiated based on market prices. We believe the differential has widened
by
several dollars per barrel. The majority of this crude oil, while light,
is a
“paraffinic” crude, and can be processed efficiently by only a limited number
of stranded inland refineries. The production of this type crude is
increasing regionally and beginning to strain the capacity of these refineries.
Other new crude sources from the region are pressuring pricing. If these
refineries limit the volumes of this parraffinic crude oil they are willing
to
process, it could impact the marketability of this type of crude which, for
Berry, represents approximately 3,500 Bbl/D of production or approximately
15%
of total current production. We are investigating the market opportunities
for
this crude oil. If market prices continue to deteriorate,
we may
allocate capital expenditures to projects which produce natural gas and crude
oils with lower paraffinic content until the refinery constraint is
resolved.
The
following companywide results are in millions (except per share data) for
the
years ended December 31:
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Sales
of oil
|
$
|
289
|
$
|
210
|
$
|
130
|
||||
|
Sales
of gas
|
61
|
17
|
6
|
|||||||
|
Total
sales of oil and gas
|
$
|
350
|
$
|
227
|
$
|
136
|
||||
|
Sales
of electricity
|
55
|
|
48
|
44
|
|
|||||
|
Interest
and other income, net
|
2
|
|
-
|
1
|
|
|||||
|
Total
revenues and other income
|
$
|
407
|
|
$
|
275
|
$
|
181
|
|
||
|
Net
income
|
$
|
112
|
|
$
|
69
|
$
|
32
|
|
||
|
Earnings
per share (diluted)
|
$
|
5.00
|
$
|
3.08
|
$
|
1.47
|
||||
 |
 |
Reserve
Replacement Rate.
The
reserve replacement rate is calculated by dividing total new proved reserves
added for the year by total production for the year. This measure is important
because it is an indication of growth in proved reserves of the Company and,
thus may impact the value of the Company. We believe our calculation of this
measure is substantially similar to how other companies compute reserve
replacement rate.
Hedging.
See Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15
to the
financial statements.
Operating
data.
The
following table is for the years ended December 31:
|
|
|
2005
|
%
|
2004
|
%
|
2003
|
%
|
|||
|
Oil
and Gas
|
|
|
|
|
|
|
||||
|
Heavy
Oil Production (Bbl/D)
|
16,063
|
70
|
15,901
|
77
|
15,477
|
94
|
||||
|
Light
Oil Production (Bbl/D)
|
3,336
|
14
|
3,345
|
16
|
489
|
3
|
||||
|
Total
Oil Production (Bbl/D)
|
|
|
19,399
|
84
|
|
19,246
|
93
|
|
15,966
|
97
|
|
Natural
Gas Production (Mcf/D)
|
|
|
21,696
|
16
|
|
7,752
|
7
|
|
3,499
|
3
|
|
Total
(BOE/D)
|
|
|
23,015
|
100
|
|
20,537
|
100
|
|
16,549
|
100
|
|
Percentage
increase from prior year
|
12%
|
24%
|
15%
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
47.01
|
|
$
|
33.64
|
|
$
|
24.48
|
|
|
Average
sales price after hedging
|
|
|
41.62
|
|
|
30.32
|
|
|
22.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
||||||||||
|
Average
WTI price
|
$
|
56.70
|
$
|
39.21
|
$
|
31.16
|
||||
|
Price
sensitive royalties
|
(4.42
|
)
|
(2.78
|
)
|
(1.79
|
)
|
||||
|
Gravity
differential
|
(5.22
|
)
|
(4.93
|
)
|
(2.97
|
)
|
||||
|
Crude
oil hedges
|
(6.21
|
)
|
(2.93
|
)
|
(2.03
|
)
|
||||
|
Average
oil sales price after hedging
|
$
|
40.85
|
$
|
28.57
|
$
|
24.37
|
||||
|
Gas,
per MMBtu:
|
||||||||||
|
Average
Henry Hub price
|
$
|
8.05
|
$
|
6.13
|
$
|
5.11
|
||||
|
Natural
gas hedges
|
(.11
|
)
|
(.01
|
)
|
.02
|
|||||
|
Location
and quality differentials
|
(1.45
|
)
|
(.63
|
)
|
(.81
|
)
|
||||
|
Average
gas sales price after hedging
|
$
|
6.49
|
$
|
5.49
|
$
|
4.32
|
||||
Electricity. Berry
consumes natural gas as fuel to operate its three cogeneration facilities
which
are intended to provide an efficient and secure long-term supply of steam
necessary for the economic production of heavy oil. We sell our electricity
to
utilities under Standard Offer contracts, under which our revenues are linked
to
the cost of natural gas. Natural gas index prices are the primary determinant
of
Berry’s electricity sales price. The correlation between electricity sales and
natural gas prices allows us to more effectively manage our cost of producing
steam. Revenue and operating costs in the year ended 2005 were up from the
year
ended 2004 due to 18% higher electricity prices and 34% higher natural gas
prices, respectively. We purchased approximately 38 MMBtu/D as fuel for use
in
our cogeneration facilities in the year ended December 31, 2005.
|
|
|
2005
|
2004
|
2003
|
|
|||||
|
Electricity
|
||||||||||
|
Revenues
(in millions)
|
$
|
55.2
|
$
|
47.6
|
$
|
44.2
|
||||
|
Operating
costs (in millions)
|
$
|
55.1
|
$
|
46.2
|
$
|
42.4
|
||||
|
Decrease
to total oil and gas operating expenses-per barrel
|
$
|
.02
|
$
|
.19
|
$
|
.32
|
||||
|
Electric
power produced - MWh/D
|
|
|
2,030
|
|
|
2,121
|
|
|
2,100
|
|
|
Electric
power sold - MWh/D
|
|
|
1,834
|
|
|
1,915
|
|
|
1,925
|
|
|
Average
sales price/MWh before hedging
|
|
$
|
82.73
|
|
$
|
70.24
|
|
$
|
62.91
|
|
|
Average
sales price/MWh after hedging
|
|
$
|
82.73
|
|
$
|
70.24
|
|
$
|
61.95
|
|
|
Fuel
gas cost/MMBtu (after hedging and excluding
transportation)
|
|
$
|
7.30
|
|
$
|
5.46
|
|
$
|
4.88
|
|
Royalties.
A
price-sensitive royalty burdens a portion of our Midway-Sunset California
property which produces approximately 3,800 barrels per day. This royalty
is 75%
of the amount of the heavy oil posted price above a base price which was
$15.18
in 2005. This base price escalates at 2% annually, thus the threshold price
is
$15.48 per barrel in 2006. Amounts paid were $29 million, $19.3 million and
$10.2 million in the years ended December 31, 2005, 2004 and 2003, respectively.
Accounts payable associated with this royalty at year end 2005 was $29 million.
Because our interest in the revenue varies according to crude prices, the
continuing development on this property will depend on its future profitability.
A
second
price sensitive royalty burdens approximately 700 barrels per day at our
Placerita field in California. This royalty is calculated when the sales
price
exceeds $26 per barrel up to a maximum. The royalty was $2.8 million, $1.4
million and $.3 million in the years ended December 31, 2005, 2004 and 2003,
respectively. The maximum amount of the royalty over its life is $5 million,
thus, we expect this royalty payable will end in the first quarter of
2006.
In
2005,
the Bureau of Land Management revoked their royalty exemption for certain
heavy
oil properties. This resulted in a reduction to Berry of .9 million barrels
of
reserves and approximately 100 BOE/D in the fourth quarter of 2005. In December
2004, certain royalty owners exercised their right to convert their royalty
interest into a working interest on our Formax property in the Midway-Sunset
field. This resulted in a reduction of 1.8 million barrels of reserves and
represented approximately 450 BOE/day as of December 31, 2004.
Oil
and Gas Operating, Production Taxes, G&A and Interest Expenses.
We
believe that the most informative way to analyze changes in recurring operating
expenses from one period to another is on a per unit-of-production, or BOE,
basis. The following table presents information about our operating expenses
for
each of the years in the two-year period ended December 31, 2005:
|
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
|
|
2005
|
|
2004
|
|
Change
|
|
2005
|
|
2004
|
|
Change
|
|
||||||
|
Operating
costs - oil and gas production
|
|
$
|
11.79
|
|
$
|
10.09
|
|
|
17
|
%
|
$
|
99,066
|
|
$
|
73,838
|
|
|
34
|
%
|
|
Production
taxes
|
1.37
|
.86
|
59
|
%
|
11,506
|
6,431
|
79
|
%
|
|||||||||||
|
DD&A
- oil and gas production
|
|
|
4.54
|
|
|
3.96
|
|
|
15
|
%
|
|
38,150
|
|
|
29,752
|
|
|
28
|
%
|
|
G&A
|
|
|
2.55
|
|
|
2.
99
|
|
|
(15)
|
%
|
|
21,396
|
|
|
22,504
|
|
|
(5)
|
%
|
|
Interest
expense
|
|
|
0.72
|
|
|
0.27
|
|
|
167
|
%
|
|
6,048
|
|
|
2,067
|
|
|
193
|
%
|
|
Total
|
|
$
|
20.97
|
|
$
|
18.17
|
|
|
15
|
%
|
$
|
176,166
|
|
$
|
134,592
|
|
|
31
|
%
|
Our
total
operating costs, production taxes, G&A and interest expenses for 2005,
stated on a unit-of-production basis, increased 15% over 2004. The changes
were
primarily related to the following items:
| · |
Operating
costs: Higher crude oil and natural gas prices have created an
incentive
for the U.S. domestic oil and gas industry to significantly increase
exploration and development activities, which is straining the
capacity
for goods and services that support our industry. Thus, higher
costs are
prominent throughout the industry and resulted in higher operating
costs
per BOE for the year ended 2005 as compared to 2004. Costs in California
were also higher due to increased well servicing activities and
increases
in steam costs. The cost of Berry’s steaming operations on our heavy oil
properties represents a significant portion of our operating costs
and
will vary depending on the cost of natural gas used as fuel and
the volume
of steam injected. The following table presents steam information:
|
|
2005
|
2004
|
Change
|
||
|
Average
volume of steam injected (Bbl/D)
|
70,032
|
69,200
|
1%
|
|
|
Fuel
gas cost/MMBtu
|
$7.30
|
$5.46
|
34%
|
|
As
commodity prices remain robust, we anticipate that cost pressures within
our
industry may continue. Natural gas prices impact our cost structure in
California by approximately $1.75 per California BOE for each $1.00 move
in
natural gas price. The California production target for 2006 is 16,700
BOE/D.
| · |
Production
taxes: Higher prices, such as those exhibited in 2005, create increased
production taxes.
|
| · |
Depreciation,
depletion and amortization: DD&A increased per BOE in the year ended
2005 from the year ended 2004 due to higher acquisition costs of
our Rocky
Mountain and Mid-Continent region assets as compared to our legacy
heavy
oil assets in California and higher finding and development costs.
As
these costs increase, our DD&A rates per BOE will also increase.
|
| · |
General
and administrative: Approximately two-thirds of Berry’s G&A is
compensation or compensation related costs. We intend to remain
competitive in workforce compensation to achieve our growth plans.
Stock-based compensation expense was $.35 per BOE and $.56 per
BOE for the
years ended December 31, 2005 and 2004, respectively. Compensation
expenses increased due to increased staffing resulting from our
growth,
and increases in compensation levels and bonuses. Additionally,
we
incurred increased legal and accounting fees, primarily due to
compliance
with Sarbanes-Oxley, and growth through acquisitions and other
financial
reporting related matters. Legal and accounting expenses were $.28
per BOE
in 2005 as compared to $.23 per BOE in
2004.
|
| · |
Interest
expense: We increased our outstanding borrowings to $75 million
at
December 31, 2005 as compared to $28 million at December 31, 2004.
Average
borrowings increased as a result of acquisitions of $112 million
during
2005. Additionally, interest rates have increased by approximately
1.75%
since December 31, 2004.
|
The
following table presents information about our operating expenses for each
of
the years in the two-year period ended December 31, 2004:
|
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
|
2004
|
|
2003
|
|
Change
|
|
2004
|
|
2003
|
|
Change
|
|
||||||
|
Operating
costs - oil and gas production
|
|
$
|
10.09
|
|
$
|
9.57
|
|
|
5
|
%
|
$
|
73,838
|
|
$
|
57,830
|
|
|
28
|
%
|
|
Production
taxes
|
.86
|
.51
|
69
|
%
|
6,431
|
3,097
|
108
|
%
|
|||||||||||
|
DD&A
- oil and gas production
|
|
|
3.96
|
|
|
2.86
|
|
|
38
|
%
|
|
29,752
|
|
|
17,258
|
|
|
72
|
%
|
|
G&A
|
|
|
2.99
|
|
|
2.40
|
|
|
25
|
%
|
|
22,504
|
|
|
14,495
|
|
|
55
|
%
|
|
Interest
expense
|
|
|
0.27
|
|
|
0.23
|
|
|
17
|
%
|
|
2,067
|
|
|
1,414
|
|
|
46
|
%
|
|
Total
|
|
$
|
18.17
|
|
$
|
15.57
|
|
|
17
|
%
|
$
|
134,592
|
|
$
|
94,094
|
|
|
43
|
%
|
Our
total
operating, production taxes, G&A and interest expenses for 2004, stated on a
unit-of-production basis, increased 17% over 2003. The changes were primarily
related to the following items:
· Operating
costs: 2004, on a per barrel basis, increased over 2003 due primarily to
higher
steam costs. The cost of Berry's steaming operations for its heavy oil
properties represents a significant portion of our operating costs
and will vary depending on both the cost of natural gas used as fuel and
the
volume of steam injected during the year. The following table presents steam
information:
|
2004
|
2003
|
Change
|
||
|
Average
volume of steam injected (Bbl/D)
|
69,200
|
63,300
|
9%
|
|
|
Fuel
gas cost/MMBtu
|
$5.46
|
$4.88
|
12%
|
· Depreciation,
depletion and amortization: 2004 was higher due to higher finding and
development costs, the shorter reserve life of our Brundage Canyon properties
in
Utah and the cumulative effect of increased development activities in recent
years. We expect DD&A to trend higher over the next few years due to the
shorter reserve life of the Rocky Mountain assets compared to our California
properties and continued development of our California and Rocky Mountain
properties.
· General
and administrative: 2004 was up from 2003 due to stock-based compensation
costs
increasing by $2.8 million in 2004, or $.56 per BOE, which are primarily
non-cash charges resulting from marked-to-market adjustments under the variable
method of accounting prior to the change of certain exercise provisions of
our
stock option plan on July 29, 2004 and non-cash compensation expense under
the
fair value method of accounting. Compensation expenses increased due to
increased staffing resulting from our growth, an increase in compensation
levels
and bonuses and costs related to a change in chief executive officers.
Additionally, we incurred increased legal and accounting fees during 2004,
primarily due to compliance with Sarbanes-Oxley and other financial reporting
related matters.
· Interest
expense: 2004 was up from 2003. Although our borrowings at year-end 2004
were
$28 million, down from $50 million in 2003, we borrowed $40 million in August
2003 to fund the acquisition of our Brundage Canyon property. We reduced
our
debt from 2003 levels during the latter half of 2004.
Estimated
2006 Oil and Gas Operating, G&A and Interest
Expenses
|
|
Amount
per BOE
|
|
||||||||
|
|
|
Anticipated
|
|
|
|
|||||
|
|
|
range
in 2006
|
|
2005
|
|
2004
|
||||
|
|
||||||||||
|
Operating
costs-oil and gas production (1)
|
$
|
13.00
to 16.00
|
|
$
|
11.79
|
|
$
|
10.09
|
||
|
Production
taxes
|
1.35
to 1.65
|
1.37
|
.86
|
|||||||
|
DD&A
|
|
|
5.75
to 6.50
|
|
|
4.54
|
|
|
3.96
|
|
|
G&A
|
|
|
2.75
to 3.00
|
|
|
2.55
|
|
|
2.99
|
|
|
Interest
expense
|
|
|
1.35
to 1.60
|
|
|
0.72
|
|
|
.27
|
|
|
Total
|
|
$
|
24.20
to 28.75
|
|
$
|
20.97
|
|
$
|
18.17
|
|
| (1) |
Assuming
natural gas prices of approximately NYMEX HH $8.50 MMBtu, we plan
to
inject steam at levels in 2006 comparable to, or slightly higher
than 2005
levels.
|
Dry
hole, abandonment and impairment. The
$5.7
million reflected on Berry’s income statement under dry hole, abandonment and
impairment is made up of the following three items:
| · |
At
December 31, 2004, we were in the process of drilling one exploratory
well
on our Midway-Sunset property and one exploratory well on our Coyote
Flats
prospect. These two wells were determined non-commercial in February
2005
and $2.2 million was incurred and expensed in 2005.
|
| · |
Two
exploratory wells at northern Brundage Canyon were expensed for
$.6
million.
|
| · |
Finally,
we impaired the remaining carrying value of our Illinois and eastern
Kansas prospective CBM acreage acquired in 2002 by $2.9 million.
|
Costs
of
$.7 million which were incurred on the Midway-Sunset property and the
exploratory well on the Coyote Flats prospect as of December 31, 2004 were
charged to expense. During 2003, we recorded a pre-tax write down of $4.2
million related to two CBM pilot projects.
Exploration
costs.
We
incurred exploration costs of $3.6 million in 2005 compared to zero costs
in
2004 and 2003. These costs consist primarily of geological and geophysical
costs. Berry participated in 3-D seismic surveys at Lake Canyon, Utah and
in the
Tri-State area. We are projecting exploration costs in 2006 of between $4
million and $6 million.
Income
Taxes.
The
Revenue Reconciliation Act of 1990 included a tax credit for certain costs
associated with extracting high-cost, capital-intensive marginal oil or gas
and
which utilizes at least one of nine designated "enhanced" or
tertiary recovery methods (EOR). Cyclic steam and steam flood recovery
methods for heavy oil, which Berry utilizes extensively, are qualifying EOR
methods. In 1996, California conformed to the federal law, thus, on a combined
basis, we are able to achieve credits approximating 12% of our qualifying
costs.
The credit is earned only for qualified EOR projects by investing in one
of
three types of expenditures: 1) drilling development wells, 2) adding facilities
that are integrally related to qualified EOR production, or 3) utilizing
a
tertiary injectant, such as steam, to produce oil. The credit may be utilized
to
reduce our tax liability down to, but not below, our alternative minimum
tax
liability. This credit has been significant through 2005 in reducing our
income
tax liabilities and effective tax rate. However, with higher crude oil prices
and the increasing investment in its light crude oil and natural gas properties,
Berry’s effective income tax rate trended higher in 2005 compared to prior
years. The average U.S. wellhead price for crude oil exceeded $43 in 2005,
thus
triggering a full phase-out of the EOR credit for 2006. If the U.S. wellhead
price of crude oil declines below the triggering point in future years, we
will
be able to claim the EOR credit on qualifying expenditures and our effective
tax
rate should decline. As of December 31, 2005 the Company has approximately
$23
million of federal and $17 million of state (California) EOR tax credit
carryforwards available to reduce future income taxes. The EOR credits will
begin to expire, if unused, in 2024 and 2015 for federal and California,
respectively.
We
experienced an effective tax rate of 31%, 23% and 12% reported in 2005, 2004
and
2003, respectively. The increase in effective tax rate during 2005 is primarily
due to a much higher (over 80%) pre-tax income in relation to consistent
EOR
credits in 2005 over 2004. Our expansion outside of California and investment
in
non-thermal projects are also key factors in the increase. We have been able
to
achieve an effective tax rate below the statutory tax rate of approximately
40%
through 2005 primarily as a result of significant EOR tax credits earned
by our
continued investment in the development of thermal EOR projects, both through
capital expenditures and continued steam injection. We expect our effective
tax
rate will be higher as the EOR credit will be non-existent for 2006 and possibly
later years, and we expect to have an effective tax rate in the 37% to 39%
range
in 2006, based on WTI prices averaging between $50 and $70. See Note 9 to
the
financial statements for further information.
Financial
Condition, Liquidity and Capital Resources. Substantial
capital is required to replace and grow reserves. We achieve reserve replacement
and growth primarily through successful development and exploration drilling
and
the acquisition of properties. Fluctuations in commodity prices have been
the
primary reason for short-term changes in our cash flow from operating
activities. The net long-term growth in our cash flow from operating activities
is the result of growth in production as affected by period to period
fluctuations in commodity prices.
Capital
Expenditures. We
establish a capital budget for each calendar year based on our development
opportunities and the expected cash flow from operations for that year. We
may
revise our capital budget during the year as a result of acquisitions and/or
drilling outcomes. Excess cash generated from operations is expected to be
applied toward acquisitions, debt reduction or other corporate purposes.
Excluding
any future acquisitions, in 2006 we plan to spend approximately $208 million
on
capital projects and anticipate funding these expenditures from internally
generated cash flow. These expenditures will be directed toward developing
reserves, increasing oil and gas production and exploration opportunities.
For
2006, Berry plans to invest approximately $146 million, or 70%, in our Rocky
Mountain and Mid-Continent region assets, and $61 million, or 30%, in our
California assets. Approximately half the capital budget is focused on
converting probable and possible reserves into proved reserves and on our
appraisal and exploratory projects. Total capital expenditures in 2005,
excluding acquisitions, were $119 million and included the drilling of
approximately 188 new wells and completing 140 workovers on our properties.
All
capital expenditures, excluding acquisitions, were funded out of internally
generated cash flow. See Item 1 Business for further details.
Dividends.
The
regular quarterly dividend was increased by 8%, from $.12 to $.13 per share,
beginning with the September 2005 dividend. The total dividend payable on
September 29, 2005 was $.23 per share which included a special $.10 per share
dividend. This is the third consecutive year that we have raised the quarterly
dividend and distributed a special dividend. This action resulted in a total
payout in 2005 of $.60 per share, up 16% from the $.52 per share paid out
in
2004 and up 28% from the $.47 per share paid out in 2003.
Working
Capital and Cash Flows. Cash
flow
from operations is dependent upon the price of crude oil and natural gas
and our
ability to increase production and manage costs. Crude oil and natural gas
prices increased in 2005 (see graphs on page 30) and we increased production
by
12%.
Our
working capital balance fluctuates as a result of the amount of borrowings
and
the timing of repayments under our credit arrangements. We used our long-term
borrowings under our credit facility primarily to fund property acquisitions.
Generally, we use excess cash to pay down borrowings under our credit
arrangement. As a result, we often have a working capital deficit or a
relatively small amount of positive working capital. In 2005, the working
capital deficit was substantially greater than 2004. The deficit is primarily
made up of changes in the following four balance sheet accounts from 2005
as
compared to 2004; a $14.7 million decrease in cash, an $11 million increase
in
the Formax royalty payable, an $11.5 million increase in the short-term line
of
credit which is used to improve cash management and a $9 million increase
in
fair value of derivatives (net liability) which is associated with our increased
use of hedging in 2005.
The
table
below compares financial condition, liquidity and capital resources changes
for
the years ended December 31 (in millions, except for production and average
prices):
|
2005
|
2004
|
Change
|
|
|
Production
(BOE/D)
|
23,015
|
20,537
|
+12%
|
|
Average
oil and gas sales prices, per BOE after hedging
|
$
41.62
|
$
30.32
|
+37%
|
|
Net
cash provided by operating activities
|
$
188
|
$
125
|
+50%
|
|
Working
capital
|
$
(54.8)
|
$
(3.8)
|
(134)%
|
|
Sales
of oil and gas
|
$
350
|
$
227
|
+54%
|
|
Long-term
debt
|
$
75
|
$
28
|
+168%
|
|
Capital
expenditures, including acquisitions and deposits on acquisitions
|
$
231
|
$
85.3
|
+171%
|
|
Dividends
paid
|
$
13.2
|
$
11.4
|
+16%
|
In
June
2005, a share repurchase program was authorized for up to an aggregate of
$50
million of Berry's outstanding Class A Common Stock. Through December 31,
2005,
we had repurchased 108,900 shares for approximately $6.3 million. See Note
7 to
the financial statements.
Hedging.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15
to the
financial statements.
Credit
Facility. See
Note
6 to the financial statements for more information. We have a $500 million
unsecured credit facility, which has a current borrowing base of $350 million
and is an integral part of our financing structure that provides improved
access
to capital and the flexibility to support growth plans.
Contractual
Obligations. Refer
to
Note 10 to the financial statements.
Application
of Critical Accounting Policies. The
preparation of financial statements in conformity with generally accepted
accounting principles requires Management to make estimates and assumptions
for
the reporting period and as of the financial statement date. These estimates
and
assumptions affect the reported amounts of assets and liabilities, the
disclosure of contingent liabilities and the reported amounts of revenues
and
expenses. Actual results could differ from those amounts.
A
critical accounting policy is one that is important to the portrayal of the
Company's financial condition and results, and requires Management to make
difficult subjective and/or complex judgments. Critical accounting policies
cover accounting matters that are inherently uncertain because the future
resolution of such matters is unknown. The Company believes the following
accounting policies are critical policies.
Successful
Efforts Method of Accounting. The
Company accounts for its oil and gas exploration and development costs using
the
successful efforts method. Geological and geophysical costs and the costs
of
carrying and retaining undeveloped properties are expensed as incurred.
Exploratory well costs are capitalized pending further evaluation of whether
economically recoverable reserves have been found. If economically recoverable
reserves are not found, exploratory well costs are expensed as dry holes.
All
exploratory wells are evaluated for economic viability within one year of
well
completion. Exploratory wells that discover potentially economic reserves
that
are in areas where a major capital expenditure would be required before
production could begin, and where the economic viability of that major capital
expenditure depends upon the successful completion of further exploratory
work
in the area, remain capitalized as long as the additional exploratory work
is
under way or firmly planned.
Oil
and Gas Reserves. Oil
and
gas reserves include proved reserves that represent estimated quantities
of
crude oil, natural gas and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions. The
Company's oil and gas reserves are based on estimates prepared by independent
engineering consultants. Reserve engineering is a subjective process that
requires judgment in the evaluation of all available geological, geophysical,
engineering and economic data. Projected future production rates, the timing
of
future capital expenditures as well as changes in commodity prices may
significantly impact estimated reserve quantities. Depreciation, depletion
and
amortization (DD&A) expense and impairment of proved properties are impacted
by the Company's estimation of proved reserves. These estimates are subject
to
change as additional information and technologies become available. Accordingly,
oil and natural gas quantities ultimately recovered and the timing of production
may be substantially different than projected. Reduction in reserve estimates
may result in increased DD&A expense, increased impairment of proved
properties and a lower standardized measure of discounted future net cash
flows.
Carrying
Value of Long-lived Assets.
Downward revisions in the Company’s estimated reserve quantities, increases in
future cost estimates or depressed crude oil or natural gas prices could
cause
the Company to reduce the carrying amounts of its properties. The Company
performs an impairment analysis of its proved properties annually by comparing
the future undiscounted net revenue per the annual reserve valuation prepared
by
the Company’s independent reserve engineers to the net book carrying value of
the assets. An analysis of the proved properties will also be performed whenever
events or changes in circumstances indicate an asset’s carrying value may not be
recoverable from future net revenue. Assets are grouped at the field level
and
if it is determined that the net book carrying value cannot be recovered
by the
estimated future undiscounted cash flow, they are written down to fair value.
Cash flows used in the impairment analysis are determined based on Management’s
estimates of crude oil and natural gas reserves, future crude oil and natural
gas prices in effect at the end of the period and costs to extract these
reserves. For its unproved properties, the Company performs an impairment
analysis annually or whenever events or changes in circumstances indicate
an
asset’s net book carrying value may not be recoverable.
Derivatives
and Hedging. The
Company follows the provisions of Statement of Financial Accounting Standards
(SFAS) No. 133, Accounting
for Derivative Instruments and Hedging Activities.
SFAS
133 requires the accounting recognition of all derivative instruments as
either
assets or liabilities at fair value. Derivative instruments that are not
hedges
must be adjusted to fair value through net income. Under the provisions of
SFAS
133, the Company may designate a derivative instrument as hedging the exposure
to change in fair value of an asset or liability that is attributable to
a
particular risk (a fair value hedge) or as hedging the exposure to variability
in expected future cash flows that are attributable to a particular risk
(a cash
flow hedge). Both at the inception of a hedge and on an ongoing basis, a
fair
value hedge must be expected to be highly effective in achieving offsetting
changes in fair value attributable to the hedged risk during the periods
that a
hedge is designated. Similarly, a cash flow hedge must be expected to be
highly
effective in achieving offsetting cash flows attributable to the hedged risk
during the term of the hedge. The expectation of hedge effectiveness must
be
supported by matching the essential terms of the hedged asset, liability
or
forecasted transaction to the
derivative
contract or by effectiveness assessments using statistical measurements.
The
Company's policy is to assess hedge effectiveness at the end of each calendar
quarter.
Income
Taxes. The
Company computes income taxes in accordance with SFAS No. 109, Accounting
for Income Taxes.
SFAS
No. 109 requires an asset and liability approach which results in the
recognition of deferred income taxes on the difference between the tax basis
of
an asset or liability and its carrying amount in the Company's financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered
or
settled, respectively. Considerable judgment is required in determining when
these events may occur and whether recovery of an asset is more likely than
not.
Additionally, the Company's federal and state income tax returns are generally
not filed before the financial statements are prepared, therefore the Company
estimates the tax basis of its assets and liabilities at the end of each
calendar year as well as the effects of tax rate changes, tax credits, and
tax
credit carryforwards. A valuation allowance is recognized if it is determined
that deferred tax assets may not be fully utilized in future periods.
Adjustments related to differences between the estimates used and actual
amounts
reported are recorded in the period in which income tax returns are filed.
These
adjustments and changes in estimates of asset recovery could have an impact
on
results of operations. The Company may generate enhanced oil recovery tax
credits from the production of its heavy crude oil in California which results
in a deferred tax asset and believes that these credits will be fully utilized
in future years and consequently has not recorded any valuation allowance
related to these credits. Due to uncertainties involved with tax matters,
the
future effective tax rate may vary significantly from the estimated current
year
effective tax rate.
Asset
Retirement Obligations.
The
Company has significant obligations to plug and abandon oil and natural gas
wells and related equipment at the end of oil and gas production operations.
The
computation of the Company's asset retirement obligations (ARO) was prepared
in
accordance with SFAS No. 143, Accounting
for Asset Retirement Obligations,
which
requires the Company to record the fair value of liabilities for retirement
obligations of long-lived assets. The adoption of SFAS No. 143 in 2002 resulted
in an immaterial difference in the liability that had been previously recorded
by the Company. Estimating the future ARO requires Management to make estimates
and judgments regarding timing, current estimates of plugging and abandonment
costs, as well as what constitutes adequate remediation. The Company obtained
estimates from third parties and used the present value of estimated cash
flows
related to its ARO to determine the fair value. Inherent in the present value
calculation are numerous assumptions and judgments including the ultimate
costs,
inflation factors, credit adjusted discount rates, timing of settlement and
changes in the legal, regulatory, environmental and political environments.
Changes in any of these assumptions can result in significant revisions to
the
estimated ARO. To the extent future revisions to these assumptions impact
the
present value of the existing ARO liability, a corresponding adjustment will
be
made to the related asset. Due to the subjectivity of assumptions and the
relatively long life of the Company's assets, the costs to ultimately retire
the
Company's wells may vary significantly from previous estimates.
Environmental
Remediation Liability. The
Company reviews, on a quarterly basis, its estimates of costs of the cleanup
of
various sites including sites in which governmental agencies have designated
the
Company as a potentially responsible party. In accordance with SFAS No. 5,
Accounting
for Contingencies,
when it
is probable that obligations have been incurred and where a minimum cost
or a
reasonable estimate of the cost of remediation can be determined, the applicable
amount is accrued. Determining when expenses should be recorded for these
contingencies and the appropriate amounts for accrual is an estimation process
that includes the subjective judgment of Management. In many cases, Management's
judgment is based on the advice and opinions of legal counsel and other
advisers, the interpretation of laws and regulations, which can be interpreted
differently by regulators or courts of law, the experience of the Company
and
other companies in dealing with similar matters and the decision of Management
on how it intends to respond to a particular matter. A change in estimate
could
impact the Company's oil and gas operating costs and the liability, if
applicable, recorded on the Company's balance sheet.
Accounting
for Business Combinations. The
Company has grown substantially through acquisitions and our business strategy
is to continue to pursue acquisitions as opportunities arise. We have accounted
for all of our business combinations using the purchase method, which is
the
only method permitted under SFAS 141. The accounting for business combinations
is complicated and involves the use of significant judgment. Under the purchase
method of accounting, a business combination is accounted for at a purchase
price based upon the fair value of the consideration given, whether in the
form
of cash, assets, stock or the assumption of liabilities. The assets and
liabilities acquired are measured at their fair values, and the purchase
price
is allocated to the assets and liabilities based upon these fair values.
The
excess of the fair value of assets acquired and liabilities assumed over
the
cost of an acquired entity, if any, is allocated as a pro rata reduction
of the
amounts that otherwise would have been assigned to certain acquired assets.
Determining
the fair values of the assets and liabilities acquired involves the use of
judgment, since some of the assets and liabilities acquired do not have fair
values that are readily determinable. Different techniques may be used to
determine fair values, including market prices, where available, appraisals,
comparisons to transactions for similar assets and liabilities and present
value
of estimated future cash flows, among others. Since these estimates involve
the
use of significant judgment, they can change as new information becomes
available.
Each
of
the business combinations completed were of interests in oil and gas assets.
We
believe the consideration we paid to acquire these assets represents the
fair
value of the assets and liabilities acquired at the time of acquisition.
Consequently, we have not recognized any goodwill from any of our business
combinations, nor do we expect to recognize any goodwill from similar business
combinations that we may complete in the future.
Stock-Based
Compensation.
Effective January 1, 2004, the Company voluntarily adopted the fair value
method
of accounting for its stock option plan as prescribed by SFAS 123, Accounting
for Stock-Based Compensation. The modified prospective method was selected
as
described in SFAS 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, the Company recognizes stock option compensation expense as
if it
had applied the fair value method to account for unvested stock options from
its
original effective date. Stock option compensation expense is recognized
from
the date of grant to the vesting date. The
fair
value of each option award is estimated on the date of grant using the
Black-Scholes option pricing model that uses the following assumptions. Expected
volatilities are based on the historical volatility of the Company's stock.
The
Company uses historical data to estimate option exercises and employee
terminations within the valuation model; separate groups of employees that
have
similar historical exercise behavior are considered separately for valuation
purposes. The expected term of options granted is based on historical exercise
behavior and represents the period of time that options granted are expected
to
be outstanding; the range results from certain groups of employees exhibiting
different exercise behavior. The risk free rate for periods within the
contractual life of the option is based on U.S. Treasury rates in effect
at the
time of grant.
Electricity
Cost Allocation. The
Company’s investment in its cogeneration facilities has been for the express
purpose of lowering steam costs in its California heavy oil operations and
securing operating control of the respective steam generation. Such cogeneration
operations produce electricity and steam and use natural gas as fuel. The
Company allocates steam costs to its oil and gas operating costs based on
the
conversion efficiency (of fuel to electricity and steam) of the cogeneration
facilities plus certain direct costs in producing steam. Electricity revenue
represents sales to the utilities. Electricity used in oil and gas operations
is
allocated at cost. A portion of the DD&A expenses associated with capital is
allocated to DD&A - oil and gas production.
Recent
Accounting Pronouncements. In
December 2004, SFAS No. 123(R), Share-Based
Payment,
was
issued which establishes standards for transactions in which an entity exchanges
its equity instruments for goods or services. This standard requires an issuer
to measure the cost of employee services received in exchange for an award
of
equity instruments based on the grant-date fair value of the award. This
eliminates the exception to account for such awards using the intrinsic method
previously allowable under Accounting Principles Board (APB) Opinion No.
25. In
April 2005 the SEC issued a rule that SFAS No. 123(R) will be effective for
annual reporting periods beginning on or after June 15, 2005. As a result,
the
Company expects to adopt this statement on January 1, 2006. The Company
previously adopted the fair value recognition provisions of SFAS No. 123,
Accounting
for Stock-Based Compensation.
Accordingly the Company believes SFAS No. 123(R) will not have a material
impact
on its financial statements; however, it continues to assess the potential
impact that the adoption of SFAS No. 123(R) will have on the classification
of
tax deductions for stock-based compensation in the statements of cash flows.
In
March
2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation
No. 47, Accounting
for Conditional Asset Retirement Obligations
(“FIN
47”). FIN 47 clarifies the definition and treatment of conditional asset
retirement obligations as discussed in FASB Statement No. 143, Accounting
for Asset Retirement Obligations.
A
conditional asset retirement obligation is defined as an asset retirement
activity in which the timing and/or method of settlement are dependent on
future
events that may be outside the control of the company. FIN 47 states that
a
company must record a liability when incurred for conditional asset retirement
obligations if the fair value of the obligation is reasonably estimable.
FIN 47
is intended to provide more information about long-lived assets and future
cash
outflows for these obligations and more consistent recognition of these
liabilities and is effective for the fiscal year end December 31, 2005. The
adoption of FIN 47 by the Company did not have an immediate affect on the
financial statements.
On
April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSP 19-1
Accounting
for Suspended Well Costs that
amends SFAS 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies,
to
permit the continued capitalization of exploratory well costs beyond one
year if
the well found a sufficient quantity of reserves to justify its completion
as a
producing well and the entity is making sufficient progress assessing the
reserves and the economic and operating viability of the project. In accordance
with the guidance in the FSP, the Company applied the requirements prospectively
in its second quarter of 2005. The adoption of FSP 19-1 by the Company did
not
have an immediate effect on the financial statements. However, it could impact
the timing of the recognition of expenses for exploratory well costs in future
periods.
In
May 2005, SFAS No. 154, Accounting
Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB
Statement No. 3 was
issued. SFAS No. 154 requires retrospective application to prior period
financial statements for changes in accounting principle, unless it is
impracticable to determine either the period-specific effects or the cumulative
effect of the change. SFAS No. 154 also requires that retrospective
application of a change in accounting principle be limited to the direct
effects
of the change. Indirect effects of a change in accounting principle should
be
recognized in the period of the accounting change. SFAS No. 154 will become
effective for the Company’s fiscal year beginning January 1, 2006. The
impact of SFAS No. 154 will depend on
the
nature and extent of any voluntary accounting changes and correction of errors
after the effective date.
In
February 2006, SFAS No. 155, Accounting
for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133
and 140 was
issued. This Statement resolves issues addressed in Statement 133 Implementation
Issue No. D1, Application
of Statement 133 to Beneficial Interests in Securitized Financial
Assets.
SFAS
No. 155 will become effective for the Company’s fiscal year after September
15, 2006. The impact of SFAS No. 155 will depend on the nature and extent
of any new derivative instruments entered into after the effective
date.
As
discussed in Note 15 to the financial statements, to minimize the effect
of a
downturn in oil and gas prices and protect the profitability of the Company
and
the economics of the Company’s development plans, from time to time the Company
enters into crude oil and natural gas hedge contracts. The terms of contracts
depend on various factors, including Management’s view of future crude oil and
natural gas prices and the Company’s future financial commitments. This price
hedging program is designed to moderate the effects of a severe crude oil
and
natural gas price downturn while allowing Berry to participate in the upside.
In
California, Berry benefits from lower natural gas pricing and elsewhere,
Berry
benefits from higher natural gas pricing. The Company has, and may hedge
both
natural gas purchases and sales as determined appropriate by Management.
Management regularly monitors the crude oil and natural gas markets and the
Company’s financial commitments to determine if, when, and at what level some
form of crude oil and/or natural gas hedging or other price protection is
appropriate in accordance with Board established policy.
Currently,
the Company’s hedges are in the form of swaps and collars. However, the Company
may use a variety of hedge instruments in the future to hedge WTI or the
index
gas price. The Company has crude oil sales contracts in place, which are
priced
based on a correlation to WTI. Natural gas (for cogeneration and conventional
steaming operations) is purchased at the SoCal border price and the Company
sells its produced gas in Colorado and Utah at the Colorado Interstate Gas
(CIG)
and Questar index prices, respectively.
The
following table summarizes the hedge position of the Company as of December
31,
2005:
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
Barrels
|
|
Average
|
|
|
|
MMBtu
|
|
Average
|
|
Term
|
|
Per
Day
|
|
Price
|
|
Term
|
|
Per
Day
|
|
Price
|
|
Crude
Oil Sales (NYMEX WTI)
|
|
|
|
|
|
Natural
Gas Sales (CIG)
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
1st
Quarter 2006
|
|
3,000
|
|
$
50.90
|
|
1st
Quarter 2006
|
|
3,000
|
|
$
7.49
|
|
2nd
Quarter 2006
|
|
3,000
|
|
$
50.20
|
|
|
|
|
|
|
|
3rd
Quarter 2006
|
|
3,000
|
|
$
49.56
|
|
|
|
|
|
|
|
|
|
Natural
Gas Purchases (SoCal Border)
|
|
|
|
|
||||
|
Collars
|
|
Floor/Ceiling
Prices
|
|
Swaps
|
|
|||||
|
1st
through 3rd Quarter 2006
|
|
7,000
|
|
$47.50
/ $70
|
|
1st
Quarter 2006
|
|
5,000
|
$
4.85
|
|
|
4th
Quarter 2006
|
10,000
|
$47.50
/ $70
|
|
2nd
Quarter 2006
|
|
5,000
|
$
4.85
|
|||
|
Full
year 2007
|
10,000
|
$47.50
/ $70
|
|
|||||||
|
Full
year 2008
|
10,000
|
$47.50
/ $70
|
|
|||||||
|
Full
year 2009
|
10,000
|
$47.50
/ $70
|
|
On
March
1, 2006, the Company entered into the following derivative instruments:
|
|
|
Average
|
|
|
|
Average
|
|||
|
|
|
MMBtu
|
|
Average
|
|
|
MMBtu
|
Average
|
|
|
Term
|
|
Per
Day
|
|
Price
|
Term
|
|
Per
Day
|
Price
|
|
|
Natural
Gas Sales (NYMEX HH)
|
|
|
|
|
Natural
Gas Sales (NYMEX HH)
|
|
|
|
|
|
Swaps
|
|
|
|
|
Collars
|
Floor/Ceiling
Prices
|
|||
|
2nd
Quarter 2006
|
|
4,000
|
|
$
6.96
|
4th
Quarter 2006
|
|
8,000
|
$8
/ $9.72
|
|
|
3rd
Quarter 2006
|
|
6,000
|
|
$
7.35
|
1st
Quarter 2007
|
12,000
|
$8
/ $16.70
|
||
|
|
2nd
Quarter 2007
|
13,000
|
$8
/ $8.82
|
||||||
|
3rd
Quarter 2007
|
14,000
|
$8
/ $9.10
|
|||||||
|
4th
Quarter 2007
|
15,000
|
$8
/ $11.39
|
|||||||
|
1st
Quarter 2008
|
16,000
|
$8
/ $15.65
|
|||||||
|
2nd
Quarter 2008
|
17,000
|
$7.50
/ $8.40
|
|||||||
|
3rd
Quarter 2008
|
19,000
|
$7.50
/ $8.50
|
|||||||
|
4th
Quarter 2008
|
21,000
|
$8
/ $9.50
|
Payments
to the Company's counterparties are triggered when the monthly average prices
are above the swap price in the case of the Company's crude oil and natural
gas
sales hedges and below the swap price for the Company's natural gas purchase
hedge positions. Conversely, payments from our counterparties are received
when
the monthly average prices are below the swap price for the Company's crude
oil
and natural gas sales hedges and above the swap price for the Company's natural
gas purchase hedge positions.
The
collar strike prices will allow the Company to protect a significant portion
of
its future cash flow if 1) oil prices decline below $47.50 per barrel while
still participating in any oil price increase up to $70 per barrel on these
volumes and 2) if gas prices decline below approximately $8 per MMBtu. These
hedges improve the Company’s financial flexibility by locking in significant
revenues and cash flow upon a substantial decline in crude oil or natural
gas
prices. It also allows the Company to develop its long-lived assets and pursue
exploitation opportunities with greater confidence in the projected economic
outcomes and allows the Company to borrow a higher amount under the credit
facility.
While
the
Company has designated its hedges as cash flow hedges in accordance with
SFAS
No. 133, Accounting
for Derivative Instruments and Hedging Activities,
it is
possible that a portion of the hedge related to the movement in the WTI to
California heavy crude oil price differential may be determined to be
ineffective. Likewise, the Company may have some ineffectiveness in its natural
gas hedges put into place on March 1, 2006, due to the movement of HH pricing
as
compared to actual sales points. If this occurs, the ineffective portion
will
directly impact net income rather than being reported as Other Comprehensive
Income. While Management believes that the differential will narrow and move
closer toward its historical level over time, there are no assurances as
to the
movement in the differential. If the differential were to change significantly,
it is possible that the Company’s hedges, when marked-to-market, could have a
material impact on earnings in any given quarter and, thus, add increased
volatility to the Company’s net income. The marked-to-market values reflect the
liquidation values of such hedges and not necessarily the values of the hedges
if they are held to maturity. Irrespective of the unrealized gains reflected
in
Other Comprehensive Income, the ultimate impact to net income over the life
of
the hedges will reflect the actual settlement values. All of these hedges
have
historically been deemed to be cash flow hedges with the marked-to-market
valuations provided by external sources, based on prices that are actually
quoted.
At
December 31, 2005, Accumulated Other Comprehensive Loss, net of income taxes,
consisted of $24.4 million of unrealized losses from the Company's crude
oil and
natural gas hedges. Deferred net losses recorded in Accumulated Other
Comprehensive Loss at December 31, 2005 are expected to be reclassified to
earnings through 2006 for the Company’s swaps and at current prices the
Company’s collars are not expected to impact earnings.
|
2005
|
2004
|
2003
|
||||||||
|
Net
reduction of sales of oil and gas revenue due to hedging activities
(in
millions)
|
|
$
|
45.3
|
|
$
|
24.9
|
|
$
|
11.8
|
|
|
Net
reduction of cost of gas due to hedging activities (in
millions)
|
$
|
5.0
|
$
|
1.3
|
$
|
.1
|
||||
|
Net
reduction in revenue per BOE due to hedging activities
|
$
|
5.39
|
$
|
3.32
|
$
|
1.96
|
The
use
of hedging transactions may involve basis risk. The Company's oil hedges
are
based on reported settlement prices on the NYMEX. The basis risk between
NYMEX
and the Company's California heavy crude oil is mitigated by the Company's
crude
oil
sales
contracts. On November 21, 2005, the Company entered into a new crude oil
sales
contract for its California production for deliveries beginning February
1,
2006. The per barrel price, calculated on a monthly basis and blended across
the
various producing locations, is the higher of 1) the WTI NYMEX crude oil
price
less a fixed differential approximating $8.15, or 2) heavy oil field postings
plus a premium of approximately $1.35. The initial term of the contract is
for
four years with a one-year renewal at the Company’s option. The Company has
redesignated its existing crude oil collars as cash flow hedges related to
California crude oil production, and there was no related effect to Other
Comprehensive Income with regard to this redesignation.
Pricing
in the existing crude oil sales agreement at Brundage Canyon is based upon
average weekly WTI minus a fixed differential of approximately $2 per barrel
through September 30, 2006. Any new contract will be negotiated based on
market
prices. Upon the expiration of these crude oil contracts, and absent any
new
contracts, the Company will be exposed to fluctuations in the basis
differentials between WTI and the posted price for its crude oil at its various
producing locations until new contracts which lock in such differential can
be
obtained.
The
use
of hedging transactions also involves the risk that the counterparties will
be
unable to meet the financial terms of such transactions. With respect to
the
Company’s hedging activities, the Company utilizes multiple counterparties on
its hedges and monitors each counterparty’s credit rating. The Company also
attempts to minimize credit exposure to counterparties through diversification.
Based
on
NYMEX futures prices as of December 31, 2005, (WTI $62.71; HH $10.83) and
due to
the backwardated nature of the futures prices as of that date, the Company
would
expect to make pre-tax future cash payments or to receive payments over the
remaining term of its crude oil and natural gas hedges in place as
follows:
|
|
|
|
|
Impact
of percent change in futures prices
|
|
|||||||||||
|
|
|
12/31/05
|
|
on
earnings
|
|
|||||||||||
|
|
|
NYMEX
Futures
|
|
-20%
|
|
-10%
|
|
+
10%
|
|
+
20%
|
|
|||||
|
Average
WTI Price
|
|
$
|
62.71
|
$
|
50.17
|
|
$
|
56.44
|
|
$
|
68.98
|
$
|
75.25
|
|||
|
Crude
Oil gain/(loss) (in millions)
|
|
|
(10.4
|
)
|
|
(.1
|
)
|
|
(5.2
|
)
|
|
(17.5
|
)
|
|
(92.8
|
)
|
|
Average
HH Price
|
|
|
10.83
|
|
8.67
|
|
|
9.75
|
|
|
11.92
|
|
13.00
|
|||
|
Natural
Gas gain/(loss) (in millions)
|
3.8
|
2.4
|
3.1
|
4.4
|
5.1
|
|||||||||||
|
|
||||||||||||||||
|
Net
pre-tax future cash (payments) and receipts by year (in
millions):
|
||||||||||||||||
|
2006
|
$
|
(6.6
|
)
|
$
|
2.3
|
$
|
(2.1
|
)
|
$
|
(11.5
|
)
|
$
|
(32.3
|
)
|
||
|
2007
|
-
|
-
|
-
|
(1.6
|
)
|
(24.8
|
)
|
|||||||||
|
2008
|
-
|
-
|
-
|
-
|
(18.7
|
)
|
||||||||||
|
2009
|
|
|
-
|
|
-
|
-
|
-
|
(11.9
|
)
|
|||||||
|
Total
|
|
$
|
(6.6
|
)
|
$
|
2.3
|
$
|
(2.1
|
)
|
$
|
(13.1
|
)
|
$
|
(87.7
|
)
|
|
Interest
Rates.
The
Company’s exposure to changes in interest rates results primarily from long-term
debt. Total long-term debt outstanding at December 31, 2005 and 2004 was
$75
million and $28 million, respectively. Interest on amounts borrowed is charged
at LIBOR plus 1.0% to 1.75%. Based on year-end 2005 borrowings, a 1% change
in
interest rates would not have a material impact on the Company’s financial
statements.
|
|
Page
|
|
Report
of PricewaterhouseCoopers LLP, an Independent Registered Public
Accounting
Firm
|
42
|
|
Balance
Sheets at December 31, 2005 and 2004
|
43
|
|
Statements
of Income for the Years Ended December 31, 2005, 2004 and 2003
|
44
|
|
Statements
of Comprehensive Income for the Years Ended December 31, 2005,
2004 and
2003
|
44
|
|
Statements
of Shareholders' Equity for the Years Ended December 31, 2005,
2004 and
2003
|
45
|
|
Statements
of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003
|
46
|
|
Notes
to the Financial Statements
|
47
|
|
Supplemental
Information About Oil & Gas Producing Activities
(unaudited)
|
65
|
Financial
statement schedules have been omitted since they are either not required,
are
not applicable, or the required information is shown in the financial statements
and related notes.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the
Board of Directors and Shareholders of Berry Petroleum Company:
We
have
completed integrated audits of Berry Petroleum Company’s December 31, 2005 and
2004 financial statements and of its internal control over financial reporting
as of December 31, 2005, and an audit of its December 31, 2003 financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our opinions, based on our audits, are
presented below.
Financial
statements
In
our
opinion, the financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Berry Petroleum
Company at December 31, 2005 and 2004, and the results of its operations
and its
cash flows for each of the three years in the period ended December 31, 2005
in
conformity with accounting principles generally accepted in the United States
of
America. These financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements
in
accordance with the standards of the Public Company Accounting Oversight
Board
(United States). Those standards require that we plan and perform the audit
to
obtain reasonable assurance about whether the financial statements are free
of
material misstatement. An audit of financial statements includes examining,
on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
Internal
control over financial reporting
Also,
in
our opinion, management’s assessment, included in Management’s Report on
Internal Control Over Financial Reporting appearing under Item 9A, that the
Company maintained effective internal control over financial reporting as
of
December 31, 2005 based on criteria established in Internal
Control - Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2005,
based on criteria established in Internal
Control - Integrated Framework
issued
by the COSO. The Company’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on the effectiveness
of the Company’s internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight
Board
(United States). Those standards require that we plan and perform the audit
to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding
of
internal control over financial reporting, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in
the
circumstances. We believe that our audit provides a reasonable basis for
our
opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and
fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures
of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use,
or
disposition of the company’s assets that could have a material effect on the
financial statements.
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may
become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/
PricewaterhouseCoopers LLP
Los
Angeles, California
March
1,
2006
BERRY
PETROLEUM COMPANY
December
31, 2005 and 2004
(In
Thousands, Except Share Information)
|
|
|
2005
|
|
2004
|
|
||
|
ASSETS
|
|
||||||
|
Current
assets:
|
|||||||
|
Cash
and cash equivalents
|
|
$
|
1,990
|
|
$
|
16,690
|
|
|
Short-term
investments available for sale
|
|
|
661
|
|
|
659
|
|
|
Accounts
receivable
|
|
|
59,672
|
|
|
34,621
|
|
|
Deferred
income taxes
|
|
|
4,547
|
|
|
3,558
|
|
|
Fair
value of derivatives
|
|
|
3,618
|
|
|
3,243
|
|
|
Prepaid
expenses and other
|
|
|
4,398
|
|
|
2,230
|
|
|
Total
current assets
|
|
|
74,886
|
|
|
61,001
|
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
552,984
|
|
|
338,706
|
|
|
Deposits
on potential property acquisitions
|
|
|
-
|
|
|
10,221
|
|
|
Long-term
deferred income taxes
|
1,600
|
-
|
|||||
|
Other
assets
|
|
|
5,581
|
|
|
2,176
|
|
|
|
|
$
|
635,051
|
|
$
|
412,104
|
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
57,783
|
|
$
|
27,750
|
|
|
Revenue
and royalties payable
|
|
|
34,920
|
|
|
23,945
|
|
|
Accrued
liabilities
|
|
|
8,805
|
|
|
6,132
|
|
|
Line
of credit
|
11,500
|
-
|
|||||
|
Income
taxes payable
|
|
|
1,237
|
|
|
1,067
|
|
|
Fair
value of derivatives
|
|
|
15,398
|
|
|
5,947
|
|
|
Total
current liabilities
|
|
|
129,643
|
|
|
64,841
|
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
55,804
|
|
|
47,963
|
|
|
Long-term
debt
|
|
|
75,000
|
|
|
28,000
|
|
|
Abandonment
obligation
|
|
|
10,675
|
|
|
8,214
|
|
|
Unearned
revenue
|
866
|
-
|
|||||
|
Fair
value of derivatives
|
|
|
28,853
|
|
|
-
|
|
|
|
|
|
171,198
|
|
|
84,177
|
|
|
Commitments
and contingencies (Notes 10 and 11)
|
|
|
|
|
|
|
|
|
Shareholders'
equity:
|
|
|
|
|
|
|
|
|
Preferred
stock, $.01 par value, 2,000,000 shares authorized; no shares
outstanding
|
|
|
-
|
|
|
-
|
|
|
Capital
stock, $.01 par value:
|
|
|
|
|
|
|
|
|
Class
A Common Stock, 50,000,000 shares authorized; 21,099,906 shares
issued and
outstanding (21,060,420 in 2004)
|
|
|
211
|
|
|
210
|
|
|
Class
B Stock, 1,500,000 shares authorized; 898,892 shares issued and
outstanding (liquidation preference of $899)
|
|
|
9
|
|
|
9
|
|
|
Capital
in excess of par value
|
|
|
56,064
|
|
|
60,676
|
|
|
Accumulated
other comprehensive loss
|
|
|
(24,380
|
)
|
|
(987
|
)
|
|
Retained
earnings
|
|
|
302,306
|
|
|
203,178
|
|
|
Total
shareholders' equity
|
|
|
334,210
|
|
|
263,086
|
|
|
|
|
$
|
635,051
|
|
$
|
412,104
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Years
ended December 31, 2005, 2004 and 2003
(In
Thousands, Except Per Share Data)
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
REVENUES
|
|
|
|
|
|
|
|
|||
|
Sales
of oil and gas
|
|
$
|
349,691
|
|
$
|
226,876
|
|
$
|
135,848
|
|
|
Sales
of electricity
|
|
|
55,230
|
|
|
47,644
|
|
|
44,200
|
|
|
Interest
and other income, net
|
|
|
1,804
|
|
|
426
|
|
|
816
|
|
|
|
|
|
406,725
|
|
|
274,946
|
|
|
180,864
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|||
|
Operating
costs - oil and gas production
|
|
|
99,066
|
|
|
73,838
|
|
|
57,830
|
|
|
Operating
costs - electricity generation
|
|
|
55,086
|
|
|
46,191
|
|
|
42,351
|
|
|
Production
taxes
|
11,506
|
6,431
|
3,097
|
|||||||
|
Exploration
costs
|
3,649
|
-
|
-
|
|||||||
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
38,150
|
|
|
29,752
|
|
|
17,258
|
|
|
Depreciation,
depletion & amortization - electricity generation
|
|
|
3,260
|
|
|
3,490
|
|
|
3,256
|
|
|
General
and administrative
|
|
|
21,396
|
|
|
22,504
|
|
|
14,495
|
|
|
Interest
|
|
|
6,048
|
|
|
2,067
|
|
|
1,414
|
|
|
Dry
hole, abandonment and impairment
|
|
|
5,705
|
|
|
745
|
|
|
4,195
|
|
|
Loss
on disposal of assets
|
|
|
-
|
|
|
410
|
|
|
-
|
|
|
|
|
|
243,866
|
|
|
185,428
|
|
|
143,896
|
|
|
Income
before income taxes
|
|
|
162,859
|
|
|
89,518
|
|
|
36,968
|
|
|
Provision
for income taxes
|
|
|
50,503
|
|
|
20,331
|
|
|
4,605
|
|
|
|
|
|
|
|
|
|
|
|||
|
Net
income
|
|
$
|
112,
356
|
|
$
|
69,187
|
|
$
|
32,363
|
|
|
|
|
|
|
|
|
|
|
|||
|
Basic
net income per share
|
|
$
|
5.10
|
|
$
|
3.16
|
|
$
|
1.49
|
|
|
|
|
|
|
|
|
|
|
|||
|
Diluted
net income per share
|
|
$
|
5.00
|
|
$
|
3.08
|
|
$
|
1.47
|
|
|
|
|
|
|
|
|
|
|
|||
|
Weighted
average number of shares of capital stock outstanding (used to
calculate
basic net income per share)
|
|
|
22,041
|
|
|
21,894
|
|
|
21,772
|
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|||
|
Stock
options
|
|
|
390
|
|
|
523
|
|
|
215
|
|
|
Other
|
|
|
59
|
|
|
53
|
|
|
44
|
|
|
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
22,490
|
|
|
22,470
|
|
|
22,031
|
|
|
|
|
|
|
|
|
|
|
|||
|
Statements
of Comprehensive Income
|
|
|||||||||
|
Years
Ended December 31, 2005, 2004 and 2003
|
||||||||||
|
(In
Thousands)
|
||||||||||
|
Net
income
|
|
$
|
112,356
|
|
$
|
69,187
|
|
$
|
32,363
|
|
|
Unrealized
gains (losses) on derivatives, net of income taxes of ($16,677),
($521),
and ($2,421), respectively
|
|
|
(25,015
|
)
|
|
(781
|
)
|
|
(3,632
|
)
|
|
Reclassification
of realized gains (losses) included in net income net of income
taxes of
$1,081, $2,284 and $1,712, respectively
|
|
|
1,622
|
|
|
3,426
|
|
|
2,569
|
|
|
Comprehensive
income
|
|
$
|
88,963
|
|
$
|
71,832
|
|
$
|
31,300
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Years
Ended December 31, 2005, 2004 and 2003
(In
Thousands, Except Per Share Data)
|
|
|
Class
A
|
|
Class
B
|
|
Capital
in Excess of Par Value
|
|
Deferred
Stock-Based Compensation
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive
Income
(Loss)
|
|
Shareholders’
Equity
|
|
||||||||
|
Balances
at January 1, 2003
|
|
$
|
209
|
|
$
|
9
|
|
$
|
52,214
|
|
$
|
(346
|
)
|
$
|
123,257
|
|
$
|
(2,569
|
)
|
$
|
172,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued
compensation costs
|
|
|
-
|
|
|
-
|
|
|
3,319
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3,319
|
|
|
|
Deferred
director fees - stock compensation
|
|
|
-
|
|
|
-
|
|
|
169
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
169
|
|
|
|
Unearned
stock-based compensation
|
|
|
-
|
|
|
-
|
|
|
773
|
|
|
(773
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Amortization
of deferred stock option compensation
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
11
|
|
|
-
|
|
|
-
|
|
|
11
|
|
|
|
Cash
dividends declared - $.47 per share
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(10,235
|
)
|
|
-
|
|
|
(10,235
|
)
|
|
|
Unrealized
loss on derivatives
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(1,063
|
)
|
|
(1,063
|
)
|
|
|
Net
income
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
32,363
|
|
|
-
|
|
|
32,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances
at December 31, 2003
|
|
209
|
|
9
|
56,475
|
|
(1,108
|
)
|
145,385
|
|
(3,632
|
)
|
197,338
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Adoption
of SFAS 123
|
|
-
|
|
-
|
(243
|
)
|
1,108
|
|
-
|
|
-
|
|
865
|
|
|||||||||
|
Stock-based
compensation (155,269 shares)
|
|
1
|
|
-
|
3,451
|
|
-
|
|
-
|
|
-
|
|
3,452
|
|
|||||||||
|
Deferred
director fees - stock compensation
|
|
-
|
|
-
|
993
|
|
-
|
|
-
|
|
-
|
|
993
|
|
|||||||||
|
Cash
dividends declared - $.52 per share
|
|
-
|
|
-
|
-
|
|
-
|
|
(11,394
|
)
|
-
|
|
(11,394
|
)
|
|||||||||
|
Unrealized
gain on derivatives
|
|
-
|
|
-
|
-
|
|
-
|
|
-
|
|
2,645
|
|
2,645
|
|
|||||||||
|
Net
income
|
|
-
|
|
-
|
-
|
|
-
|
|
69,187
|
|
-
|
|
69,187
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Balances
at December 31, 2004
|
|
210
|
|
9
|
60,676
|
|
-
|
|
203,178
|
|
(987
|
)
|
263,086
|
|
|||||||||
|
Share
repurchase (108,900 shares)
|
|
|
(2
|
)
|
-
|
(6,314
|
)
|
-
|
-
|
-
|
(6,316
|
)
|
|||||||||||
|
Stock-based
compensation (147,179 shares)
|
|
|
3
|
-
|
1,360
|
-
|
-
|
-
|
1,363
|
||||||||||||||
|
Deferred
director fees - stock compensation
|
|
|
-
|
-
|
342
|
-
|
-
|
-
|
342
|
||||||||||||||
|
Cash
dividends declared - $.60 per share
|
|
|
-
|
-
|
-
|
-
|
(13,228
|
)
|
-
|
(13,228
|
)
|
||||||||||||
|
Unrealized
loss on derivatives
|
|
|
-
|
-
|
-
|
-
|
-
|
(23,393
|
)
|
(23,393
|
)
|
||||||||||||
|
Net
income
|
|
|
-
|
-
|
-
|
-
|
112,356
|
-
|
112,356
|
||||||||||||||
|
|
|
|
|||||||||||||||||||||
|
Balances
at December 31, 2005
|
|
$
|
211
|
$
|
9
|
$
|
56,064
|
$
|
-
|
$
|
302,306
|
$
|
(24,380
|
)
|
$
|
334,210
|
|||||||
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Years
Ended December 31, 2005, 2004 and 2003
(In
Thousands)
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|||
|
Net
income
|
|
$
|
112,356
|
|
$
|
69,187
|
|
$
|
32,363
|
|
|
Depreciation,
depletion and amortization
|
|
|
41,410
|
|
|
33,242
|
|
|
20,514
|
|
|
Dry
hole, abandonment and impairment
|
|
|
4,324
|
|
(569
|
)
|
|
3,756
|
|
|
|
Stock-based
compensation expense
|
|
|
1,703
|
|
5,309
|
|
|
2,872
|
|
|
|
Deferred
income taxes, net
|
|
|
20,847
|
|
10,815
|
|
|
1,496
|
|
|
|
Other,
net
|
|
|
278
|
|
794
|
|
|
400
|
|
|
|
Increase
in current assets other than cash, cash equivalents and short-term
investments
|
|
|
(26,717
|
)
|
|
(11,310
|
)
|
|
(9,034
|
)
|
|
Increase
in current liabilities other than line of credit
|
|
|
33,579
|
|
17,145
|
|
|
12,458
|
|
|
|
Net
cash provided by operating activities
|
|
|
187,780
|
|
124,613
|
|
|
64,825
|
|
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
||
|
Exploration
and development of oil and gas properties
|
|
|
(118,718
|
)
|
|
(71,556
|
)
|
|
(41,061
|
)
|
|
Property
acquisitions
|
|
|
(112,249
|
)
|
|
(2,845
|
)
|
|
(48,579
|
)
|
|
Additions
to vehicles, drilling rigs and other fixed assets
|
(11,762
|
)
|
(669
|
)
|
(494
|
)
|
||||
|
Deposits
on potential acquisitions
|
|
|
-
|
|
(10,221
|
)
|
|
-
|
|
|
|
Proceeds
from sale of assets
|
|
|
130
|
|
101
|
|
|
1,890
|
|
|
|
Other,
net
|
|
|
-
|
|
3
|
|
|
521
|
|
|
|
Net
cash used in investing activities
|
|
|
(242,599
|
)
|
|
(85,187
|
)
|
|
(87,723
|
)
|
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
||
|
Proceeds
from issuance of line of credit
|
18,000
|
-
|
-
|
|||||||
|
Payment
of line of credit
|
(6,500
|
)
|
-
|
-
|
||||||
|
Proceeds
from issuance of long-term debt
|
|
|
144,000
|
|
-
|
|
|
40,000
|
|
|
|
Payment
of long-term debt
|
|
|
(97,000
|
)
|
|
(22,000
|
)
|
|
(5,000
|
)
|
|
Dividends
paid
|
|
|
(13,228
|
)
|
|
(11,394
|
)
|
|
(10,235
|
)
|
|
Book
overdraft
|
1,921
|
-
|
-
|
|||||||
|
Repurchase
of shares
|
(6,315
|
)
|
-
|
-
|
||||||
|
Other,
net
|
|
|
(759
|
)
|
-
|
(1,075
|
)
|
|||
|
Net
cash provided by (used in) financing activities
|
|
|
40,119
|
|
(33,394
|
)
|
|
23,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash and cash equivalents
|
|
|
(14,700
|
)
|
|
6,032
|
|
|
792
|
|
|
Cash
and cash equivalents at beginning of year
|
|
|
16,690
|
|
|
10,658
|
|
|
9,866
|
|
|
Cash
and cash equivalents at end of year
|
|
$
|
1,990
|
|
$
|
16,690
|
|
$
|
10,658
|
|
|
Supplemental
disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
Interest
paid
|
|
$
|
5,275
|
|
$
|
1,243
|
|
$
|
2,125
|
|
|
Income
taxes paid
|
|
$
|
26,544
|
|
$
|
11,652
|
|
$
|
2,510
|
|
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(decrease) in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
Current
(net of income taxes of $(3,631), $1,202, and ($635),
respectively)
|
|
$
|
(5,446
|
)
|
$
|
1,804
|
|
$
|
(952
|
)
|
|
Non-current
(net of income taxes of $(11,965), $561, and ($74),
respectively)
|
|
|
(17,947
|
)
|
|
841
|
|
|
(111
|
)
|
|
Net
increase (decrease) to accumulated other comprehensive
income
|
|
$
|
(23,393
|
)
|
$
|
2,645
|
|
$
|
(1,063
|
)
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
1. General
The
Company is an independent energy company engaged in the production, development,
acquisition, exploitation and exploration of crude oil and natural gas. The
Company has 74% of its oil and gas reserves in California and 26% in the
Rocky
Mountain and Mid-Continent region. Approximately 70% of the Company's production
is in California, most of which is heavy crude oil and is sold to a Bakersfield,
California refinery. The Company has invested in cogeneration facilities
which
provide steam required for the extraction of heavy oil and which generates
electricity for sale. Production of light crude oil and natural gas in the
Rocky
Mountain and Mid-Continent region accounts for approximately 30% of the
Company’s production.
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires Management to
make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as of the
date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
2. Summary
of Significant Accounting Policies
Cash
and cash equivalents
- The
Company considers all highly liquid investments purchased with a remaining
maturity of three months or less to be cash equivalents. The Company’s cash
management process provides for the daily funding of checks as they are
presented to the bank. Included in accounts payable at December 31, 2005
is $1.9
million representing outstanding checks in excess of the bank balance (book
overdraft).
Short-term
investments
- All
short-term investments are classified as available for sale. Short-term
investments consist principally of United States treasury notes and corporate
notes with remaining maturities of more than three months at date of acquisition
and are carried at fair value. The Company utilizes specific identification
in
computing realized gains and losses on investments sold.
Accounts
receivable
-
Trade
accounts receivable are recorded at the invoiced amount and do not bear
interest. The Company does not have any off-balance-sheet credit exposure
related to its customers. The Company assesses credit risk and allowance
for
doubtful accounts on a customer specific basis. As of December 31, 2005 and
2004, the Company does not have an allowance for doubtful accounts.
Income
taxes
-
Income
taxes are provided based on the liability method of accounting. The provision
for income taxes is based on reported pre-tax financial statement income.
Deferred tax assets and liabilities are recognized for the future expected
tax
consequences of temporary differences between income tax and financial
reporting, and principally relate to differences in the tax bases of assets
and
liabilities and their reported amounts using enacted tax rates in effect
for the
year in which differences are expected to reverse. If it is more likely than
not
that some portion or all of a deferred tax asset will not be realized, a
valuation allowance is recognized.
Hedging
-
SFAS
No.
133, Accounting
for Derivative Instruments and Hedging Activities,
as
amended, requires that all derivative instruments subject to the requirements
of
the statement be measured at fair value and recognized as assets or liabilities
in the balance sheet. The accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation is generally established at the inception of a derivative. For
derivatives designated as cash flow hedges and meeting the effectiveness
guidelines of SFAS No. 133, changes in fair value, to the extent effective,
are
recognized in other comprehensive income until the hedged item is recognized
in
earnings. The hedging relationship between the hedging instruments and hedged
items, such as oil and gas, must be highly effective in achieving the offset
of
changes in cash flows attributable to the hedged risk, both at the inception
of
the hedge and on an ongoing basis. The Company measures hedge effectiveness
at
least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time, or in the case of options
based on the change in intrinsic value. Any change in fair value of a derivative
resulting from ineffectiveness or an excluded component of the gain/loss,
such
as time value for option contracts, is recognized immediately in the statements
of income. Gains and losses on hedging instruments and adjustments of the
carrying amounts of hedged items are included in revenues for hedges related
to
the Company's crude oil and natural gas sales and in operating expenses for
hedges related to the Company's natural gas consumption. The resulting cash
flows are reported as cash flows from operating activities. See Note 15 -
Hedging.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
Oil
and gas properties, buildings and equipment
-
The
Company accounts for its oil and gas exploration and development costs using
the
successful efforts method. Geological and geophysical costs and the costs
of
carrying and retaining undeveloped properties are expensed as incurred.
Exploratory well costs are capitalized pending further evaluation of whether
economically recoverable reserves have been found. If economically recoverable
reserves are not found, exploratory well costs are expensed as dry holes.
All
exploratory wells are evaluated for economic viability within one year of
well
completion and the related capitalized costs are reviewed quarterly. Exploratory
wells that discover potentially economic reserves that are in areas where
a
major capital expenditure would be required before production could begin,
and
where the economic viability of that major capital expenditure depends upon
the
successful completion of further exploratory work in the area, remain
capitalized if the well found a sufficient quantity of reserves to justify
its
completion as a producing well and the Company is making sufficient progress
assessing the reserves and the economic and operating viability of the project.
The costs of development wells are capitalized whether productive or
nonproductive.
Depletion
of oil and gas producing properties is computed using the units-of-production
method. Depreciation of lease and well equipment, including cogeneration
facilities and other steam generation equipment and facilities, is computed
using the units-of-production method or on a straight-line basis over estimated
useful lives ranging from 10 to 20 years. Buildings and equipment are recorded
at cost. Depreciation is provided on a straight-line basis over estimated
useful
lives ranging from 5 to 30 years for buildings and improvements and 3 to
10
years for machinery and equipment. Estimated residual salvage value is
considered when determining depreciation, depletion and amortization (DD&A)
rates.
Assets
are grouped at the field level and if it is determined that the book value
of
long-lived assets cannot be recovered by estimated future undiscounted cash
flows, they are written down to fair value. When assets are sold, the applicable
costs and accumulated depreciation and depletion are removed from the accounts
and any gain or loss is included in income. Expenditures for maintenance
and
repairs are expensed as incurred.
Asset
retirement obligations
-
The
Company has significant obligations to plug and abandon oil and natural gas
wells and related equipment at the end of oil and gas production operations.
The
computation of the Company's asset retirement obligations (ARO) is prepared
in
accordance with SFAS No. 143, Accounting
for Asset Retirement Obligations.
Under
this standard, the Company records the fair value of the future abandonment
as
capitalized abandonment costs in Oil and Gas Properties with an offsetting
abandonment liability. The Company obtains estimates from third parties and
uses
the present value of estimated cash flows related to its ARO to determine
the
fair value. The capitalized abandonment costs are amortized with other property
costs using the units-of-production method. The Company increases the liability
monthly by recording accretion expense using the Company’s credit adjusted
interest rate. Accretion expense is included in DD&A in the Company’s
financial statements.
Revenue
recognition
-
Revenues
associated with sales of crude oil, natural gas, and electricity are recognized
when title passes to the customer, net of royalties, discounts and allowances,
as applicable. Electricity and natural gas produced by the Company and used
in
the Company’s operations are not included in revenues. Revenues from crude oil
and natural gas production from properties in which the Company has an interest
with other producers are recognized on the basis of the Company's net working
interest (entitlement method).
Conventional
steam costs
-
The
costs
of producing conventional steam are included in “Operating costs - oil and gas
production.”
Cogeneration
operations
-
The
Company’s investment in its cogeneration facilities has been for the express
purpose of lowering steam costs in its heavy oil operations and securing
operating control of the respective steam generation. Such cogeneration
operations produce electricity and steam. The Company allocates steam costs
to
its oil and gas operating costs based on the conversion efficiency of the
cogeneration facilities plus certain direct costs in producing steam.
Electricity revenue represents sales to the utilities. Electricity used in
oil
and gas operations is allocated at cost. Electricity consumption included
in oil
and gas operating costs for the years ended December 31, 2005, 2004 and 2003
was
$5.7 million, $5 million and $4.2 million, respectively.
Shipping
and handling costs
-
Shipping
and handling costs, which consist primarily of natural gas transportation
costs,
are included in both "Operating costs - oil and gas production" or "Operating
costs - electricity generation,” as applicable. Natural gas transportation costs
included in these categories were $5.8 million, $5.4 million and $4 million,
for
2005, 2004 and 2003, respectively.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
Production
taxes
-
Consist
primarily of severance and ad valorem taxes.
Stock-based
compensation
-
Effective
January 1, 2004, the Company voluntarily adopted the fair value method of
accounting for its stock option plan as prescribed by SFAS 123, Accounting
for Stock-Based Compensation.
The
modified prospective method was selected as described in SFAS 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, the Company recognizes stock option compensation expense as
if it
had applied the fair value method to account for unvested stock options from
its
original effective date. Stock option compensation expense is recognized
from
the date of grant to the vesting date.
From
January 1, 2004 to July 29, 2004 a portion of the Company's stock option
compensation was calculated under variable accounting; however, the majority
of
stock option compensation was accounted for under the fair value method.
In
accordance with variable plan accounting, the Company recognized a corresponding
liability determined by a marked-to-market valuation of the Company's stock
at
each financial reporting date. The Company revised certain stock option exercise
provisions of the plan and, subsequent to July 29, 2004, variable plan
accounting was no longer required.
Had
compensation cost for the Company’s stock-based compensation plan (see Note 12)
been based upon the fair value at the grant dates for awards under the plan
consistent with SFAS No. 123, the Company’s compensation cost, net of related
tax effects, net income and earnings per share would have been recorded as
the
pro forma amounts indicated below (in thousands, except per share
data):
|
|
|
2003
|
|
|
|
Net
income, as reported
|
|
$
|
32,363
|
|
|
Plus
compensation cost (net of tax), as reported
|
|
|
2,335
|
|
|
Less
compensation cost (net of tax), pro forma
|
|
(1,323
|
)
|
|
|
Net
income, pro forma
|
|
$
|
33,375
|
|
|
|
|
|
||
|
Basic
net income per share:
|
|
|
|
|
|
As
reported
|
|
$
|
1.49
|
|
|
Pro
forma
|
|
$
|
1.53
|
|
|
|
|
|
|
|
|
Diluted
net income per share:
|
|
|
|
|
|
As
reported
|
|
$
|
1.47
|
|
|
Pro
forma
|
|
$
|
1.52
|
|
Under
SFAS No. 123, compensation cost would be recognized for the fair value of
the
employee's option rights. The fair value of each option grant was estimated
on
the date of grant using the Black-Scholes option-pricing model with the
following assumptions:
|
|
2003
|
|
||
|
Yield
|
|
2.87
|
%
|
|
|
Expected
option life - years
|
|
7.0
|
|
|
|
Volatility
|
|
27.87
|
%
|
|
|
Risk-free
interest rate
|
|
3.86
|
%
|
|
Comprehensive
income (loss)
-
Comprehensive
income (loss) includes net earnings (loss) as well as unrealized gains and
losses on derivative instruments, recorded net of tax.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
Net
income per share
-
Basic
net
income per share is computed by dividing income available to shareholders
(the
numerator) by the weighted average number of shares of capital stock outstanding
(the denominator). The Company’s Class B Stock is included in the denominator of
basic and diluted net income. The computation of diluted net income per share
is
similar to the computation of basic net income per share except that the
denominator is increased to include the dilutive effect of the additional
common
shares that would have been outstanding if all convertible securities had
been
converted to common shares during the period.
Environmental
expenditures
-
The
Company reviews, on a quarterly basis, its estimates of costs of the cleanup
of
various sites, including sites in which governmental agencies have designated
the Company as a potentially responsible party. When it is probable that
obligations have been incurred and where a minimum cost or a reasonable estimate
of the cost of compliance or remediation can be determined, the applicable
amount is accrued. For other potential liabilities, the timing of accruals
coincides with the related ongoing site assessments. Any liabilities arising
hereunder are not discounted.
Accounting
for business combinations
- The
Company has accounted for all of its business combinations using the purchase
method, which is the only method permitted under SFAS 141, Accounting
for Business Combinations.
Under
the purchase method of accounting, a business combination is accounted for
at a
purchase price based upon the fair value of the consideration given, whether
in
the form of cash, assets, stock or the assumption of liabilities. The assets
and
liabilities acquired are measured at their fair values, and the purchase
price
is allocated to the assets and liabilities based upon these fair values.
The
excess of the fair value of assets acquired and liabilities assumed over
the
cost of an acquired entity, if any, is allocated as a pro rata reduction
of the
amounts that otherwise would have been assigned to certain acquired assets.
The
Company has not recognized any goodwill from any business combinations.
Recent
accounting developments
-
In
December 2004, SFAS No. 123(R), Share-Based
Payment,
was
issued which establishes standards for transactions in which an entity exchanges
its equity instruments for goods or services. This standard requires an issuer
to measure the cost of employee services received in exchange for an award
of
equity instruments based on the grant-date fair value of the award. This
eliminates the exception to account for such awards using the intrinsic method
previously allowable under Accounting Principles Board (APB) Opinion No.
25. In
April 2005 the SEC issued a rule that SFAS No. 123(R) will be effective for
annual reporting periods beginning on or after June 15, 2005. As a result,
the
Company expects to adopt this statement on January 1, 2006. The Company
previously adopted the fair value recognition provisions of SFAS No. 123,
Accounting
for Stock-Based Compensation.
Accordingly the Company believes SFAS No. 123(R) will not have a material
impact
on its financial statements; however, it continues to assess the potential
impact that the adoption of SFAS No. 123(R) will have on the classification
of
tax deductions for stock-based compensation in the statements of cash
flows.
In
March
2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation
No. 47, Accounting
for Conditional Asset Retirement Obligations
(“FIN
47”). FIN 47 clarifies the definition and treatment of conditional asset
retirement obligations as discussed in FASB Statement No. 143, Accounting
for Asset Retirement Obligations.
A
conditional asset retirement obligation is defined as an asset retirement
activity in which the timing and/or method of settlement are dependent on
future
events that may be outside the control of the company. FIN 47 states that
a
company must record a liability when incurred for conditional asset retirement
obligations if the fair value of the obligation is reasonably estimable.
FIN 47
is intended to provide more information about long-lived assets and future
cash
outflows for these obligations and more consistent recognition of these
liabilities. FIN 47 is effective for the fiscal year end December 31, 2005.
The
adoption of FIN 47 by the Company did not have an impact on the financial
statements.
On
April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSP 19-1
Accounting
for Suspended Well Costs that
amends SFAS 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies,
to
permit the continued capitalization of exploratory well costs beyond one
year if
the well found a sufficient quantity of reserves to justify its completion
as a
producing well and the entity is making sufficient progress assessing the
reserves and the economic and operating viability of the project. In accordance
with the guidance in the FSP, the Company applied the requirements prospectively
in its second quarter of fiscal 2005. The adoption of FSP 19-1 by the Company
did not have an effect on the financial statements. However, it could impact
the
timing of the recognition of expenses for exploratory well costs in future
periods.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
In
May 2005, SFAS No. 154, Accounting
Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB
Statement No. 3 was
issued. SFAS No. 154 requires retrospective application to prior period
financial statements for changes in accounting principle, unless it is
impracticable to determine either the period-specific effects or the cumulative
effect of the change. SFAS No. 154 also requires that retrospective
application of a change in accounting principle be limited to the direct
effects
of the change. Indirect effects of a change in accounting principle should
be
recognized in the period of the accounting change. SFAS No. 154 will become
effective for the Company’s fiscal year beginning January 1, 2006. The
impact of SFAS No. 154 will depend on the nature and extent of any
voluntary accounting changes and correction of errors after the effective
date.
In
February 2006, SFAS No. 155, Accounting
for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133
and 140 was
issued. This Statement resolves issues addressed in Statement 133 Implementation
Issue No. D1, Application
of Statement 133 to Beneficial Interests in Securitized Financial
Assets.
SFAS
No. 155 will become effective for the Company’s fiscal year after September
15, 2006. The impact of SFAS No. 155 will depend on the nature and extent
of any new derivative instruments entered into after the effective
date.
Revisions
to the classification of technical labor costs and production
taxes
-
In
connection with the preparation of the 2005 financial statements the Company
is
reclassifying technical labor between general and administrative expenses
and
operating costs-oil and gas and reclassifying production taxes out of operating
costs-oil and gas into a separate line. These reclassifications had no impact
on
net income or net cash provided by operating activities and did not effect
previously reported total revenues, total operating expenses, net income
or net
cash provided by operating activities. Accordingly, the Company has revised
prior classifications for the year ended December 31, 2004 as follows (in
thousands):
|
|
|
2004
|
|
2003
|
||
|
Operating
costs - oil and gas
|
|
|
|
|||
|
As
previously reported
|
|
$
|
82,419
|
$
|
62,554
|
|
|
As
revised
|
|
73,838
|
57,830
|
|||
|
Difference
|
|
$
|
8,581
|
$
|
4,724
|
|
|
|
|
|||||
|
Production
taxes
|
|
|
|
|||
|
As
previously reported
|
|
$
|
-
|
$
|
-
|
|
|
As
revised
|
|
|
6,431
|
|
3,097
|
|
|
Difference
|
|
$
|
(6,431)
|
$
|
(3,097)
|
|
|
G&A
expenses
|
|
|
|
|||
|
As
previously reported
|
|
$
|
20,354
|
$
|
12,868
|
|
|
As
revised
|
|
|
22,504
|
|
14,495
|
|
|
Difference
|
|
$
|
(2,150)
|
$
|
(1,627)
|
|
3. Fair
Value of Financial Instruments
Cash
equivalents consist principally of commercial paper investments. Cash
equivalents of $2 million and $16.7 million at December 31, 2005 and 2004,
respectively, are stated at cost, which approximates market.
The
Company’s short-term investments available for sale at December 31, 2005 and
2004 consist of United States treasury notes that mature in less than one
year
and are carried at fair value. For the three years ended December 31, 2005,
realized and unrealized gains and losses were insignificant to the financial
statements. A United States treasury note with a market value of $.7 million
is
pledged as collateral to the California State Lands Commission as a performance
bond on the Company’s Montalvo properties. The carrying value of the Company’s
long-term debt approximates its fair value since the interest rate is variable.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
4. Concentration
of Credit Risks
The
Company sells oil, gas and natural gas liquids to pipelines, refineries and
oil
companies and electricity to utility companies. Credit is extended based
on an
evaluation of the customer’s financial condition and historical payment
record.
Because
of the Company’s ability to deliver significant volumes of crude oil over a
multi-year period, the Company secured a thirty-nine month sales agreement,
beginning in late 2002, with a major California refiner whereby the Company
sold
over 90% of its California production under a negotiated pricing mechanism.
This
contract ended on January 31, 2006. Pricing in this agreement was based upon
the
higher of the average of the local field posted prices plus a fixed premium,
or
WTI minus a fixed differential near $6.00 per barrel. Both methods were
calculated using a monthly determination. In addition to providing a premium
above field postings, the agreement effectively eliminated the Company’s
exposure to the risk of widening WTI to California heavy crude price
differentials and allowed the Company to effectively hedge its production
based
on WTI pricing.
On
November 21, 2005, the Company entered into a new crude oil sales contract
for
its California production for deliveries beginning February 1, 2006. The
per
barrel price, calculated on a monthly basis and blended across the various
producing locations, is the higher of 1) the WTI NYMEX crude oil price less
a
fixed differential approximating $8.15, or 2) heavy oil field postings plus
a
premium of approximately $1.35. The initial term of the contract is for four
years with a one-year renewal at the Company’s option.
For
the
three years ended December 31, 2005, the Company has experienced no credit
losses on the sale of oil, gas and natural gas liquids.
The
Company places its temporary cash investments with high quality financial
institutions and limits the amount of credit exposure to any one financial
institution. For the three years ended December 31, 2005, the Company has
not
incurred losses related to these investments. With respect to the Company’s
hedging activities, the Company utilizes more than one counterparty on its
hedges and monitors each counterparty’s credit rating.
The
following summarizes the accounts receivable balances at December 31, 2005
and
2004 and sales activity with significant customers for each of the years
ended
December 31, 2005, 2004 and 2003 (in thousands). The Company does not believe
that the loss of any one customer would impact the marketability of its
California crude oil, gas, natural gas liquids or electricity sold.
Due to
the possibility of refinery constraints in the Utah region, it is possible
that
the loss of the current crude oil sales customer could impact the marketability
of a portion of the Company’s Utah crude oil volumes. The Company is
investigating its market opportunities for this Utah crude oil.
|
|
|
Accounts
Receivable
|
|
Sales
|
|
|||||||||||
|
|
|
For
the Year Ended December 31,
|
|
For
the Year Ended December 31,
|
|
|||||||||||
|
Customer
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
2003
|
|
|||||
|
Oil
& Gas Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
A
|
|
$
|
24,389
|
|
$
|
18,391
|
|
$
|
291,093
|
|
$
|
202,966
|
|
$
|
142,422
|
|
|
B
|
|
|
6,929
|
|
|
5,465
|
|
|
81,342
|
|
|
58,807
|
|
|
5,566
|
|
|
C
|
|
|
1,086
|
|
|
670
|
|
|
11,863
|
|
|
9,138
|
|
|
6,524
|
|
|
|
|
$
|
32,404
|
|
$
|
24,526
|
|
$
|
384,298
|
|
$
|
270,911
|
|
$
|
154,512
|
|
|
Electricity
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
D
|
|
$
|
4,375
|
|
$
|
3,402
|
|
$
|
24,391
|
|
$
|
21,755
|
|
$
|
20,334
|
|
|
E
|
|
|
7,806
|
|
|
2,764
|
|
|
30,893
|
|
|
26,524
|
|
|
24,616
|
|
|
|
|
$
|
12,181
|
|
$
|
6,166
|
|
$
|
55,284
|
|
$
|
48,279
|
|
$
|
44,950
|
|
Sales
amounts will not agree to the Statements of Income due primarily to the effects
of hedging and price sensitive royalties paid on a portion of the Company’s
crude oil sales, which are netted in “Sales of oil and gas” on the Statements of
Income.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment
Oil
and
gas properties, buildings and equipment consist of the following at December
31
(in thousands):
|
|
|
2005
|
|
2004
|
|
||
|
Oil
and gas:
|
|
|
|
|
|
||
|
Proved
properties:
|
|
|
|
|
|
||
|
Producing
properties, including intangible drilling costs
|
|
$
|
437,032
|
|
$
|
260,566
|
|
|
Lease
and well equipment(1)
|
|
|
275,346
|
|
|
236,932
|
|
|
|
|
|
712,378
|
|
|
497,498
|
|
|
Unproved
properties
|
|
|
|
|
|
|
|
|
Properties,
including intangible drilling costs
|
|
|
36,440
|
|
|
5,569
|
|
|
Lease
and well equipment
|
|
|
267
|
|
|
2,498
|
|
|
|
|
|
36,707
|
|
|
8,067
|
|
|
|
|
|
749,085
|
|
|
505,565
|
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
208,597
|
|
|
168,994
|
|
|
|
|
|
540,488
|
|
|
336,571
|
|
|
Commercial
and other:
|
|
|
|
|
|
|
|
|
Land
|
|
|
496
|
|
|
297
|
|
|
Buildings
and improvements
|
|
|
4,351
|
|
|
3,703
|
|
|
Machinery
and equipment
|
|
|
17,016
|
|
|
6,681
|
|
|
|
|
|
21,863
|
|
|
10,681
|
|
|
Less
accumulated depreciation
|
|
|
9,367
|
|
|
8,546
|
|
|
|
|
|
12,496
|
|
|
2,135
|
|
|
|
|
$
|
552,984
|
|
$
|
338,706
|
|
|
(1)Includes
cogeneration facility costs.
|
|
|
|
|
|
|
|
The
following sets forth costs incurred for oil and gas property acquisition,
development and exploration activities, whether capitalized or expensed (in
thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Property
acquisitions (1)
|
|
|
|
|
|
|
|
|||
|
Proved
properties
|
|
$
|
97,348
|
|
$
|
440
|
|
$
|
49,326
|
|
|
Unproved
properties
|
|
|
24,566
|
|
|
2,405
|
|
|
853
|
|
|
Development (2)
|
|
|
112,255
|
|
|
66,664
|
|
|
42,391
|
|
|
Exploration
|
|
|
7,661
|
|
|
5,506
|
|
|
788
|
|
|
|
|
$
|
241,830
|
|
$
|
75,015
|
|
$
|
93,358
|
|
(1)
Costs incurred for proved and unproved property acquisitions in 2005 include
the
reclassification of 2004 deposits of $5,505 and $4,716,
respectively..
(2)
Development
costs include $.6 million, $.7 million and $.9 million that were charged
to
expense during 2005, 2004 and 2003, respectively.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment (Cont'd)
In
2005,
the Tri-State area is comprised of the following three acquisitions totaling
approximately 315,000 net acres:
| · |
Niobrara
gas producing assets in Yuma County in northeastern Colorado in
which the
Company has approximately 52% working interest were purchased for
approximately $105 million.
|
| · |
Eastern
Colorado, western Kansas and southwestern Nebraska assets in which
the
Company has approximately 50% working interest were purchased for
approximately $5 million.
|
| · |
Colorado’s
Phillips and Sedgwick Counties in which the Company has approximately
50%
working interest were purchased for approximately $.9 million.
This
Niobrara leasehold position is adjacent to and immediately north
of
Berry’s producing natural gas assets in Yuma County.
|
In
2005,
the Company completed several transactions whereby it now has working interests
in 186,000 gross acres (46,000 net) located in the Williston Basin in North
Dakota. These lease acquisitions, totaling approximately $11 million, cover
several contiguous blocks located primarily on the eastern flank of the Nesson
Anticline.
In
July
2004, the Company purchased approximately 169,000 gross acres with an industry
partner in the Lake Canyon prospect in Utah, of which 124,500 gross (62,250
net)
acres are leased from the Ute Tribe and 44,500 gross (22,250 net) acres are
fee
lands. Total cost to Berry was approximately $2 million. The Company will
drill
and operate shallow wells which target light oil in the Green River formation
and retain a 75% working interest. The Company’s partner will drill and operate
deeper wells and the Company will retain a 25% working interest. The Ute
Tribe
has the option to participate in all wells and retain up to a 25% working
interest. As of December 31, 2005, the Company's minimum obligation under
its
agreement is $9.6 million through 2009.
In
2003,
the Company purchased leases totaling 45,380 acres in the Brundage Canyon
field
in Utah for approximately $45 million and the McVan property totaling 560
acres
in the Poso Creek field in Kern County, California for approximately $2.6
million. The Company capitalized approximately $2.6 million in future
abandonment obligations related to the 2003 acquisitions.
|
Results
of operations from oil and gas producing
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
and
exploration activities (in thousands):
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Sales
to unaffiliated parties
|
|
$
|
349,691
|
$
|
226,876
|
|
$
|
135,848
|
|
|
|
Production
costs
|
|
|
(110,572
|
)
|
|
(80,269
|
)
|
|
(60,927
|
)
|
|
Depreciation,
depletion and amortization
|
|
|
(38,150
|
)
|
|
(29,752
|
)
|
|
(17,258
|
)
|
|
Dry
hole, abandonment and impairment
|
|
|
(5,705
|
)
|
|
(745
|
)
|
|
(4,195
|
)
|
|
|
|
|
195,264
|
|
116,110
|
|
|
53,468
|
|
|
|
Income
tax expenses
|
|
|
(59,664
|
)
|
|
(33,840
|
)
|
|
(9,340
|
)
|
|
|
|
|
|
|
|
|
|
|
||
|
Results
of operations from producing and exploration activities
|
|
$
|
135,600
|
$
|
82,270
|
|
$
|
44,128
|
|
|
The
following table provides an aging of capitalized exploratory well costs based
on
the date the drilling was completed and the number of wells for which
exploratory well costs have been capitalized for a period of greater than
one
year since the completion of drilling (in thousands, except number of
projects):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Capitalized
exploratory well costs that have been capitalized for a period
of one year
or less
|
|
$
|
6,037
|
|
$
|
2,941
|
|
$
|
511
|
|
|
Capitalized
exploratory well costs that have been capitalized for a period
greater
than one year
|
|
|
-
|
|
|
511
|
|
|
-
|
|
|
Balance
at December 31
|
|
$
|
6,037
|
|
$
|
3,452
|
|
$
|
511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of projects that have exploratory well costs that have been capitalized
for a period of greater than one year
|
|
|
-
|
|
|
1
|
|
|
-
|
|
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment (Cont'd)
The
following table reflects the net changes in capitalized exploratory well
costs
during the years ended 2005, 2004 and 2003 (in thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Beginning
balance at January 1
|
|
$
|
3,452
|
|
$
|
511
|
|
$
|
1,684
|
|
|
Additions
to capitalized exploratory well costs pending the determination
of proved
reserves
|
|
|
8,840
|
|
|
3,420
|
|
|
1,081
|
|
|
Reclassifications
to wells, facilities and equipment based on the determination of
proved
reserves
|
|
|
(3,369
|
)
|
|
-
|
|
|
-
|
|
|
Capitalized
exploratory well costs charged to expense
|
|
|
(2,886
|
)
|
|
479
|
|
|
2,254
|
|
|
Ending
balance at December 31
|
|
$
|
6,037
|
$
|
3,452
|
|
$
|
511
|
|
|
In
2004,
included in the amount of exploratory well costs that have been capitalized
for
a period of greater than one year since completion of drilling are costs
of $.5
million that have been capitalized since 2003. These costs are related to
the
Company's diatomite project in the Midway-Sunset field and have been
reclassified from exploratory well costs in 2005.
Dry
hole, abandonment and impairment.
The
$5.7
million reflected on the Company’s income statement under dry hole, abandonment
and impairment is made up of the following three items:
| · |
At
December 31, 2004, the Company was in the process of drilling one
exploratory well on its Midway-Sunset property and one exploratory
well on
its Coyote Flats prospect. These two wells were determined non-commercial
in February 2005 and $2.2 million was incurred and expensed in
2005.
|
| · |
Two
exploratory wells at northern Brundage Canyon were expensed for
$.6
million.
|
| · |
Finally,
the Company impaired the remaining carrying value of its Illinois
and
eastern Kansas prospective CBM acreage acquired in 2002 by $2.9
million.
|
Costs
of
$.7 million which were incurred on the Midway-Sunset property and the
exploratory well on the Coyote Flats prospect as of December 31, 2004 were
charged to expense. During 2003, the Company recorded a pre-tax write down
of
$4.2 million related to two CBM pilot projects.
6. Long-term
and Short-term Debt Obligations
|
|
|
2005
|
|
2004
|
|
||
|
Long-term
debt for the years ended December 31 (in thousands):
|
|
|
|
|
|
||
|
Revolving
bank facility
|
|
$
|
75,000
|
|
$
|
28,000
|
|
Long-term
debt
In
June
2005, the Company completed a new unsecured five year bank credit agreement
(the
Agreement) with a banking syndicate. The Agreement is a revolving credit
facility for up to $500 million with nine banks and replaces the previous
$200
million facility which was due to mature in 2006. Initial borrowings were
$125
million which represented an amount equal to the borrowings outstanding under
the previous credit facility and the initial borrowing base was established
as
$350 million. This transaction is considered a modification of a debt instrument
due to modification of terms in accordance with Emerging Issues Task Force,
(EITF) 98-14,
Debtor’s Accounting forChanges in Line of Credit or Revolving Debt
Arrangements.
The
credit available under the Agreement is $264 million at December 31, 2005
without any increase to the borrowing base. The maximum amount available
is
subject to an annual redetermination of the borrowing base in accordance
with
the lender's customary procedures and practices. Both the Company and the
banks
have bilateral rights to one additional redetermination each year.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
6. Long-term
and Short-term Debt Obligations (Cont’d)
The
Agreement matures on July 1, 2010. Interest on amounts borrowed is charged
at
LIBOR plus a margin of 1.00% to 1.75%, or the higher of the lead bank’s prime
rate or the federal funds rate plus .50% plus a margin of 0% to .50% at the
Company’s option, with margins on the various rate options based on the ratio of
credit outstanding to the borrowing base. The Company is required under the
Agreement to pay an annual commitment fee of .25% to .38% on the unused portion
of the credit facility.
The
weighted average interest rate on outstanding borrowings at December 31,
2005
and 2004 was 4.9% and 3.37%, respectively. The Agreement contains restrictive
covenants which, among other things, require the Company to maintain a certain
debt to EBITDA ratio and a minimum current ratio, as defined. The Company
was in
compliance with all such covenants as of December 31, 2005.
Short-term
debt
In
November 2005, the Company completed a new unsecured uncommitted money market
line of credit (Line of Credit). Borrowings under the Line of Credit may
be up
to $30 million for a maximum of 30 days. The Line of Credit may be terminated
at
any time upon written notice by either the Company or the lender. At December
31, 2005 the outstanding balance under this Line of Credit was $11.5 million.
Interest on amounts borrowed is charged at LIBOR plus a margin of approximately
1%. The weighted average interest rate on outstanding borrowings at December
31,
2005 was 5.4%.
7. Shareholders’
Equity
Shares
of
Class A Common Stock (Common Stock) and Class B Stock, referred to collectively
as the "Capital Stock," are each entitled to one vote and 95% of one vote,
respectively. Each share of Class B Stock is entitled to a $1.00 per share
preference in the event of liquidation or dissolution. Further, each share
of
Class B Stock is convertible into one share of Common Stock at the option
of the
holder.
The
Company's Capital Stock activity follows (in number of shares):
|
|
|
Class
A
|
|
Class
B
|
|
||
|
December
31, 2002
|
|
20,852,695
|
898,892
|
||||
|
Shares
issued from option exercises
|
|
51,683
|
-
|
||||
|
Shares
repurchased and retired
|
|
(6
|
)
|
-
|
|||
|
December
31, 2003
|
|
20,904,372
|
898,892
|
||||
|
Shares
issued from option exercises
|
|
155,269
|
-
|
||||
|
Shares
issued under Director deferred compensation plan
|
|
797
|
-
|
||||
|
Shares
repurchased and retired
|
|
(18
|
)
|
-
|
|||
|
December
31, 2004
|
|
21,060,420
|
898,892
|
||||
|
Shares
issued from option exercises
|
|
147,179
|
-
|
||||
|
Shares
issued under Director deferred compensation plan
|
|
1,207
|
-
|
||||
|
Shares
repurchased and retired
|
|
(108,900
|
)
|
-
|
|||
|
December
31, 2005
|
|
21,099,906
|
898,892
|
||||
In
June
2005, the Company announced that its Board of Directors authorized a share
repurchase program for up to an aggregate of $50 million of the Company's
outstanding Class A Common Stock. Through December 31, 2005, the Company
repurchased 108,900 shares for approximately $6.3 million.
In
December 2005, the Company adopted a plan under Rule 10b5-1 of the Securities
Exchange Act of 1934 to facilitate the repurchase of its shares of common
stock.
Rule 10b5-1 allows a company to purchase its shares at times when it would
not
normally be in the market due to possession of nonpublic information, such
as
the time immediately preceding its quarterly earnings releases. This 10b5-1
plan
is authorized under, and is administered consistent with, the Company's $50
million share repurchase program. All repurchases of common stock are made
in
compliance with regulations set forth by the SEC and are subject to market
conditions, applicable legal requirements and other factors.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
7. Shareholders’
Equity (Cont'd)
This
program does not obligate the Company to acquire any particular amount of
common
stock and the plan may be suspended at any time at the Company's
discretion.
Dividends
In
2005,
the Company paid a special dividend of $.10 per share on September 29, 2005
and
increased its regular quarterly dividend by 8%, from $.12 to $.13 per share
beginning with the September 29, 2005 dividend. The Company's annual dividend
is
currently $.52 per share, paid quarterly in March, June, September and
December.
In
2004,
the Company paid a special dividend of $.06 per share on September 29, 2004
and
increased its regular quarterly dividend by 9%, from $.11 to $.12 per share
beginning with the September 2004 dividend. In 2003, the Company paid a special
dividend of $.04 per share on May 2, 2003 and increased its regular quarterly
dividend by 10%, from $.10 to $.11 per share beginning with the June 2003
dividend.
As
of
December 31, 2005, dividends declared on 3,984,080 shares of certain Common
Stock are restricted, whereby 37.5% of the dividends declared on these shares
are paid by the Company to the surviving member of a group of individuals,
the B
Group, as long as this remaining member shall live.
Dividend
payments are limited by a covenant in the Company's credit facility to the
greater of $20 million or 75% of net income.
Shareholder
Rights Plan
In
November 1999, the Company adopted a Shareholder Rights Agreement and declared
a
dividend distribution of one Right for each outstanding share of Capital
Stock
on December 8, 1999. Each Right, when exercisable, entitles the holder to
purchase one one-hundredth of a share of a Series B Junior Participating
Preferred Stock, or in certain cases other securities, for $38.00. The exercise
price and number of shares issuable are subject to adjustment to prevent
dilution. The Rights would become exercisable, unless earlier redeemed by
the
Company, 10 days following a public announcement that a person or group has
acquired, or obtained the right to acquire, 20% or more of the outstanding
shares of Common Stock or 10 business days following the commencement of
a
tender or exchange offer for such outstanding shares which would result in
such
person or group acquiring 20% or more of the outstanding shares of Common
Stock,
either event occurring without the prior consent of the Company.
The
Rights will expire on December 8, 2009 or may be redeemed by the Company
at $.01
per Right prior to that date unless they have theretofore become exercisable.
The Rights do not have voting or dividend rights, and until they become
exercisable, have no diluting effect on the earnings of the Company. A total
of
250,000 shares of the Company’s Preferred Stock has been designated Series B
Junior Participating Preferred Stock and reserved for issuance upon exercise
of
the Rights.
8. Asset
Retirement Obligations
Under
SFAS 143, the following table summarizes the change in abandonment obligation
for the years ended December 31 (in thousands):
|
|
|
2005
|
|
2004
|
|
||
|
Beginning
balance at January 1
|
|
$
|
8,214
|
$
|
7,311
|
|
|
|
Liabilities
incurred
|
|
|
2,952
|
|
769
|
|
|
|
Liabilities
settled
|
|
|
(1,382
|
)
|
|
(570
|
)
|
|
Accretion
expense
|
|
|
891
|
|
704
|
|
|
|
|
|
|
|
|
|
||
|
Ending
balance at December 31
|
|
$
|
10,675
|
$
|
8,214
|
|
|
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
9. Income
Taxes
The
provision for income taxes consists of the following (in
thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Current:
|
|
|
|
|
|
|
|
|||
|
Federal
|
|
$
|
22,666
|
$
|
7,073
|
|
$
|
2,490
|
|
|
|
State
|
|
|
6,990
|
|
2,443
|
|
|
619
|
|
|
|
|
|
|
29,656
|
|
9,516
|
|
|
3,109
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
||
|
Federal
|
|
|
20,640
|
|
11,959
|
|
|
2,027
|
|
|
|
State
|
|
|
207
|
|
(1,144
|
)
|
|
(531
|
)
|
|
|
|
|
|
20,847
|
|
10,815
|
|
|
1,496
|
|
|
|
Total
|
|
$
|
50,503
|
$
|
20,331
|
|
$
|
4,605
|
|
|
The
current deferred tax assets and liabilities are offset and presented as a
single
amount in the financial statements. Similarly, the non-current deferred tax
assets and liabilities are presented in the same manner. The following table
summarizes the components of the total deferred tax assets and liabilities
before such financial statement offsets. The components of the net deferred
tax
liability consist of the following at December 31
(in thousands):
|
|
|
2005
|
|
2004
|
|
||
|
Deferred
tax asset:
|
|
|
|
|
|
||
|
Federal
benefit of state taxes
|
|
$
|
2,712
|
$
|
1,308
|
|
|
|
Credit
carryforwards
|
|
|
31,929
|
|
26,478
|
|
|
|
Stock
option costs
|
|
|
2,352
|
|
1,700
|
|
|
|
Derivatives
|
|
|
16,253
|
|
658
|
|
|
|
Other,
net
|
|
|
139
|
|
1,610
|
|
|
|
|
|
|
53,385
|
|
31,754
|
|
|
|
Deferred
tax liability:
|
|
|
|
|
|
||
|
Depreciation
and depletion
|
|
|
(102,754
|
)
|
|
(76,311
|
)
|
|
Other,
net
|
|
|
(289
|
)
|
|
152
|
|
|
|
|
|
|
|
|
||
|
|
|
|
(103,043
|
)
|
|
(76,159
|
)
|
|
|
|
|
|
|
|
||
|
Net
deferred tax liability
|
|
$
|
(49,658
|
)
|
$
|
(44,405
|
)
|
At
December 31, 2005, the Company's net deferred tax assets and liabilities
were
recorded as a current asset of $4.5 million and a net long-term liability
of
$54.2 million. At December 31, 2004, the Company's net deferred tax assets
and
liabilities were recorded as a current asset of $3.6 million and a long-term
liability of $48 million.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
9. Income
Taxes (Cont’d)
Reconciliation
of the statutory federal income tax rate to the effective income tax rate
follows:
|
|
|
2005
|
|
2004
|
|
2003
|
||||
|
Tax
computed at statutory federal rate
|
|
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State
income taxes, net of federal benefit
|
|
|
3
|
|
|
1
|
|
|
1
|
|
|
Tax
credits
|
|
|
(7
|
)
|
|
(9
|
)
|
|
(24
|
)
|
|
Recognition
of tax basis of properties
|
|
|
-
|
|
(5
|
)
|
|
-
|
|
|
|
Other
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
Effective
tax rate
|
|
|
31
|
%
|
|
23
|
%
|
|
12
|
%
|
The
Company has approximately $23 million of federal and $17 million of state
(California) EOR tax credit carryforwards available to reduce future income
taxes. The EOR credits will begin to expire, if unused, in 2024 and 2015
for
federal and California, respectively.
10. Commitments
The
Company's contractual obligations as of December 31, 2005 are as follows
(in
thousands):
|
Contractual
Obligations
|
|
Total
|
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter
|
|||||||
|
Long-term
debt and interest
|
|
$
|
79,500
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
79,500
|
$
|
-
|
$
|
-
|
|
Abandonment
obligations
|
|
|
10,675
|
|
315
|
|
360
|
|
539
|
|
556
|
|
556
|
|
8,349
|
|
Operating
lease obligations
|
|
|
802
|
|
538
|
|
138
|
|
108
|
|
18
|
|
-
|
|
-
|
|
Drilling
and rig obligations
|
|
|
16,698
|
|
8,948
|
|
2,400
|
|
2,950
|
|
2,400
|
|
-
|
|
-
|
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
||||||
|
transportation
contracts
|
|
|
36,454
|
|
3,706
|
|
4,574
|
|
4,398
|
|
4,386
|
|
4,386
|
|
15,004
|
|
Total
|
|
$
|
144,129
|
$
|
13,507
|
$
|
7,472
|
$
|
7,995
|
$
|
86,860
|
$
|
4,942
|
$
|
23,353
|
Long-term
debt and interest
-
Long-term debt and related interest of approximately 6% on the long-term
debt
borrowings can be paid before its maturity date without significant
penalty.
Operating
leases -
The
Company leases corporate and field offices in California and in Denver. Rent
expense with respect to the Company's lease commitments for the years ended
December 31, 2005, 2004 and 2003 was $.6 million, $.6 million, and $.5 million,
respectively.
Drilling
obligation
-
The
Company intends to participate in the drilling of over 16 gross wells on
its
Lake Canyon prospect over the next four years. The Company's minimum obligation
under its exploration and development agreement is $9.6 million.
Drilling
rig obligation
- The
Company is obligated in operating lease agreements for two drilling rigs,
each
for one year ending in 2006.
Firm
natural gas transportation
-
The
Company entered into several firm transportation contracts which provide
the
Company additional flexibility in securing its natural gas supply and allows
the
Company to potentially benefit from lower natural gas prices in the Rocky
Mountains compared to natural gas prices in California.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
11. Contingencies
The
Company has accrued environmental liabilities for all sites, including sites
in
which governmental agencies have designated the Company as a potentially
responsible party, where it is probable that a loss will be incurred and
the
minimum cost or amount of loss can be reasonably estimated. However, because
of
the uncertainties associated with environmental assessment and remediation
activities, future expense to remediate the currently identified sites, and
sites identified in the future, if any, could be higher than the liability
currently accrued. Amounts currently accrued are not significant to the
financial position of the Company and Management believes, based upon current
site assessments, that the ultimate resolution of these matters will not
require
substantial additional accruals. The Company is involved in various other
lawsuits, claims and inquiries, most of which are routine to the nature of
its
business. In the opinion of Management, the resolution of these matters will
not
have a material effect on the Company’s financial position, results of
operations or liquidity.
12. Equity
Compensation Plans
On
December 2, 1994, the Board of Directors of the Company adopted the Berry
Petroleum Company 1994 Stock Option Plan which was restated and amended in
December 1997 and December 2001 (the 1994 Plan or Plan) and approved by the
shareholders in May 1998 and May 2002, respectively. The 1994 Plan provided
for
the granting of stock options to purchase up to an aggregate of 3,000,000
shares
of Common Stock. All options, with the exception of the formula grants to
non-employee Directors, were granted at the discretion of the Compensation
Committee of the Board of Directors. The term of each option did not exceed
ten
years from the date the options were granted. The 1994 Plan expired on December
2, 2004, and the shareholders approved a new equity incentive plan in May
2005.
The
2005
Equity Incentive Plan (the 2005 Plan) provides for granting of equity
compensation to purchase up to an aggregate of 1,450,000 shares of Common
Stock.
All equity grants are at market value on the date of grant and at the discretion
of the Compensation Committee or the Board of Directors. The term of each
employee grant did not exceed ten years from the grant date and vest 25%
per
year for 4 years. The 2005 Plan also allows for grants to non-employee
Directors. During 2005, each of the non-employee Directors received 5,000
options at the market value on the date of grant. The options granted to
the
non-employee Directors vest immediately.
Stock
Options
Effective
January 1, 2004, the Company voluntarily adopted the fair value method of
accounting for its stock option plans as prescribed by SFAS 123, Accounting
for Stock-Based Compensation.
The
modified prospective method was selected as described in SFAS 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, the Company recognized stock option compensation expense as
if it
had applied the fair value method to account for unvested stock options from
its
original effective date. Compensation expense under the fair value method
for
the years ended December 31, 2005 and 2004 was $2.9 million and $1.5 million,
respectively. Additionally, the Company recorded $4.4 million and $3.9 million
for the years ended December 31, 2004 and 2003, respectively, in compensation
expense under the variable method of accounting prior to the modification
of
certain exercise provisions of the Company's 1994 Plan on July 29,
2004.
The
fair
value of each option award is estimated on the date of grant using the
Black-Scholes option pricing model that uses the assumptions noted in the
following table. Expected volatilities are based on the historical volatility
of
the Company's stock. The Company uses historical data to estimate option
exercises and employee terminations within the valuation model; separate
groups
of employees that have similar historical exercise behavior are considered
separately for valuation purposes. The expected term of options granted is
based
on historical exercise behavior and represents the period of time that options
granted are expected to be outstanding; the range given below results from
certain groups of employees exhibiting different exercise behavior. The risk
free rate for periods within the contractual life of the option is based
on U.S.
Treasury rates in effect at the time of grant.
|
|
2005
|
|
2004
|
|
Expected
volatility
|
28%
- 32%
|
|
25%
|
|
Weighted-average
volatility
|
32%
|
|
25%
|
|
Expected
dividends
|
.92%
- 1.3%
|
|
1.27%
- 2.45%
|
|
Expected
term (in years)
|
4
-
5
|
|
4
-
7
|
|
Risk-free
rate
|
3.8%
- 4.4%
|
|
3.4%
- 4.4%
|
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
12. Equity
Compensation Plans (Cont'd)
The
following table summarizes information related to stock options outstanding
and
exercisable as of December 31, 2005:
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
Average
|
|
|
|
Weighted
|
|
Range
of
|
|
|
|
Average
|
|
Remaining
|
|
|
|
Average
|
|
Exercise
|
|
Options
|
|
Exercise
|
|
Contractual
|
|
Options
|
|
Exercise
|
|
Prices
|
|
Outstanding
|
|
Price
|
|
Life
|
|
Exercisable
|
|
Price
|
|
$10.63
- $23.76
|
|
707,575
|
|
$17.27
|
6.61
|
514,475
|
|
$16.80
|
||
|
$23.77
- $36.90
|
|
103,500
|
|
28.79
|
8.47
|
25,875
|
|
28.79
|
||
|
$36.91
- $50.04
|
479,875
|
|
43.21
|
8.94
|
131,188
|
|
43.26
|
|||
|
$50.05
- $63.18
|
|
264,463
|
|
61.25
|
9.95
|
40,000
|
|
61.29
|
||
|
Total
|
|
1,555,413
|
|
$33.52
|
8.02
|
711,538
|
|
$24.61
|
Weighted
average option exercise price information for the years ended December 31
is as
follows:
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Outstanding
at January 1
|
|
$
|
25.41
|
|
$
|
16.50
|
|
$
|
15.17
|
|
|
Granted
during the year
|
|
|
59.13
|
|
|
40.60
|
|
|
19.31
|
|
|
Exercised
during the year
|
|
|
16.80
|
|
|
15.73
|
|
|
13.15
|
|
|
Cancelled/expired
during the year
|
|
|
37.36
|
|
|
18.02
|
|
|
16.55
|
|
|
Outstanding
at December 31
|
|
|
33.52
|
|
|
25.41
|
|
|
16.50
|
|
|
Exercisable
at December 31
|
|
|
24.61
|
|
|
17.61
|
|
|
15.62
|
|
The
following is a summary of stock option activity for the years ended December
31
is as follows:
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Balance
outstanding, January 1
|
|
|
1,565,625
|
|
|
1,701,925
|
|
|
1,604,575
|
|
|
Granted
|
|
|
299,463
|
|
|
567,750
|
|
|
411,500
|
|
|
Exercised
|
|
|
(302,600
|
)
|
|
(581,550
|
)
|
|
(294,150
|
)
|
|
Canceled/expired
|
|
|
(7,075
|
)
|
|
(122,500
|
)
|
|
(20,000
|
)
|
|
Balance
outstanding, December 31
|
|
|
1,555,413
|
|
|
1,565,625
|
|
|
1,701,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
exercisable at December 31
|
|
|
711,538
|
|
|
688,275
|
|
|
1,037,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available
for future grant
|
|
|
1,150,537
|
|
|
-
|
|
|
615,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average remaining contractual life (years)
|
|
|
8
|
|
|
8
|
|
|
7
|
|
|
Weighted
average fair value per option granted during the year based on
the
Black-Scholes pricing model
|
|
$
|
19.16
|
|
$
|
10.10
|
|
$
|
5.11
|
|
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
12. Equity
Compensation Plans (Cont'd)
The
total
intrinsic value of options exercised during the years ended December 31,
2005,
2004 and 2003, was $12.6 million, $7.2 million and $1.6 million, respectively.
At December 31, 2005, the intrinsic value of options outstanding was $36.8
million and the intrinsic value of exercisable options was $26.2
million.
As
of
December 31, 2005, there was $8.2 million of total unrecognized compensation
cost related to stock options granted under the Plan. This cost is expected
to
be recognized over a weighted-average period over 4 years.
Restricted
Stock Units
Under
the
2005 Equity Incentive Plan, the Company began a long-term incentive program
whereby restricted stock units (RSUs) are available for grant to certain
employees and
vest 25%
per year over 4 years. In 2005, 70,950
RSUs were granted with a weighted average fair value per unit granted during
the
year of $61.29. As
of
December 31, 2005, there was $3.7 million of total unrecognized compensation
cost related to RSUs granted under the Plan. This cost is expected to be
recognized over a weighted-average period of 4 years, which is also the weighted
average remaining contractual life. Unearned compensation under the restricted
stock award plan is amortized over the vesting period. The Company will pay
cash
compensation on the RSUs in an equivalent amount of actual dividends paid
on a
per share basis of the Company’s outstanding common stock.
13. 401(k)
Plan
The
Company sponsors a defined contribution thrift plan under section 401(k)
of the
Internal Revenue Code to assist all eligible employees in providing for
retirement or other future financial needs. Employee contributions (up to
6% of
earnings) were matched by the Company at a range of $1 for $1 up to a maximum
of
$1.50 for $1 based on monthly profit levels for the Company. Effective November
1, 1992, the 401(k) Plan was modified to provide for increased Company matching
of employee contributions whereby the monthly Company matching contributions
will range from 6% to 9% of eligible participating employee earnings, if
certain
financial targets are achieved. The Company's contributions to the 401(k)
Plan
were $1.1 million, $.8 million and $.5 million in 2005, 2004 and 2003,
respectively. Approximately 99% of full-time employees participate in the
Plan.
In December 2005, the 401(k) Plan was amended whereby effective January 1,
2006,
the Company’s matching contribution will be $1 for $1 up to a maximum of 8% of
an employee’s eligible compensation.
14. Director
Deferred Compensation Plan
The
Company established a non-employee director deferred stock and compensation
plan
to permit eligible directors, in recognition of their contributions to the
Company, to receive fees as compensation and defer recognition of their
compensation in whole or in part to a Stock Unit Account or an Interest Account.
When the eligible director ceases to be a director, the distribution from
the
Stock Unit Account shall be made in shares using an established market value
date and the distribution from the Interest Account shall be made in cash.
The
aggregate number of shares which may be issued to eligible directors under
the
plan shall not exceed 250,000, subject to adjustment for corporate transactions
that change the amount of outstanding stock. The plan may be amended at any
time, not more than once every six months, by the Compensation Committee
or the
Board of Directors and shall terminate, unless extended, on May 31,
2008.
Amounts
allocated to the Stock Unit Account have the right to receive an amount equal
to
the dividends per share declared by the Company on the applicable dividend
payment date and this “dividend equivalent” shall be treated as reinvested in an
additional number of units and credited to their account using an established
market value date. Amounts allocated to the Interest Account are credited
with
interest at an established interest rate.
Shares
earned and deferred in accordance with the plan as of December 31, 2005,
2004
and 2003 were 6,885, 7,481 and 11,037, respectively.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
15. Hedging
From
time
to time, the Company enters into crude oil and natural gas hedge contracts,
the
terms of which depend on various factors, including Management’s view of future
crude oil and natural gas prices and the Company’s future financial commitments.
This hedging program is designed to moderate the effects of a severe crude
oil
price downturn and protect certain operating margins in the Company's California
operations. Currently, the hedges are in the form of swaps and collars, however,
the Company may use a variety of hedge instruments in the future. Management
regularly monitors the crude oil and natural gas markets and the Company’s
financial commitments to determine if, when, and at what level some form
of
crude oil and/or natural gas hedging or other price protection is appropriate.
All of these hedges have historically been deemed to be cash flow hedges
with
the marked-to-market valuations provided by external sources, based on prices
that are actually quoted.
In
June
2005, the Company entered into derivative instruments (zero-cost collars)
for
approximately 10,000 Bbl/D for the period January 1, 2006 through December
31,
2009. Based on WTI pricing, the floor is $47.50 and the ceiling is $70 per
barrel. Upon entering into the new crude oil sales contract for California
production in November 2005, the Company redesignated its existing crude
oil
collars as cash flow hedges related to California crude oil production, and
there was no related effect to Other Comprehensive Income with regard to
this
redesignation. The use of hedging transactions also involves the risk that
the
counterparties will be unable to meet the financial terms of such transactions.
With respect to the Company’s hedging activities, the Company utilizes multiple
counterparties on its hedges and monitors each counterparty’s credit rating.
After the June hedge transaction, a significant credit risk concentration
existed in one broker. In July 2005, the Company reduced the concentration
as
the hedges were transferred to multiple counterparties. The Company is not
required to issue collateral on these hedging transactions.
At
December 31, 2005 and 2004, Accumulated Other Comprehensive Loss consisted
of $24.4 million and $1 million, respectively, net of tax of unrealized losses
from the Company's crude oil and natural gas swaps and collars. Deferred
net
losses recorded in Accumulated Other Comprehensive Loss at December 31,
2005 are expected to be reclassified to earnings over the life of the underlying
hedging contracts.
| 16. |
Pro
Forma Results (unaudited)
|
On
January 27, 2005, the Company acquired certain interests in the Niobrara
field
in northeastern Colorado for approximately $105 million (J-W Acquisition)
to
increase natural gas reserves and production. Assets purchased include $93
million of gas properties, $6 million of pipeline, and $ 5 million of
compression equipment. Liabilities assumed included $1 million of asset
retirement obligations.
The
unaudited pro forma results presented below for the year ended December 31,
2005
and 2004 have been prepared to give effect to the J-W Acquisition on the
Company’s results of operations under the purchase method of accounting as if it
had been consummated on January 1, 2004. The unaudited pro forma results
do not
purport to represent the results of operations that actually would have occurred
on such date or to project the Company’s results of operations for any future
date or period. (in thousands, except per share data):
|
2005
|
2004
|
||||
|
Proforma
Revenue
|
$
408,088
|
$
295,243
|
|||
|
Proforma
Income from operations
|
190,970
|
121,688
|
|||
|
Proforma
Net income
|
112,660
|
72,393
|
|||
|
Proforma
Basic earnings per share
|
5.11
|
3.31
|
|||
|
Proforma
Diluted earnings per share
|
5.01
|
3.22
|
|||
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
| 17. |
Lease
Receivable
|
Canyon
Drilling LLC (“Canyon”), a 100% owned Colorado entity, was dissolved in the
third quarter of 2005. Canyon owned a drilling rig which was leased to a
third
party. After the dissolution, the drilling rig is 100% owned by the Company.
Concurrent with the dissolution of Canyon, the original lease was terminated
and
a revised three-year lease agreement was executed which has similar terms
to the
original lease. The revised lease includes a three year purchase option.
The
total net investment in the revised lease is approximately $3.4 million and
is
accounted for as a direct financing lease as defined by SFAS No. 13,
Accounting
for Leases.
Net
investment in this lease as of December 31, 2005 is as follows (in
thousands):
|
Net
minimum lease payments receivable
|
$
4,781
|
|
|
Unearned
income
|
(1,382
|
)
|
|
Net
investment in direct financing lease
|
$
3,399
|
Estimated
future minimum lease payments, including the purchase option, to be received
as
of December 31, 2005 are as follows (in thousands):
|
2006
|
$
504
|
||
|
2007
|
504
|
||
|
2008
|
3,773
|
||
|
Total
|
$
4,781
|
Drilling
Rigs
During
2005, the Company purchased two drilling rigs. The first rig is leased to
a
drilling company under a three-year contract (see above), while the second
rig
is currently being refurbished in preparation for leasing under a similar
drilling contract. Both rigs carry purchase options available to the drilling
company.
18. Quarterly
Financial Data (unaudited)
The
following is a tabulation of unaudited quarterly operating results for 2005
and
2004 (in thousands, except per share data).
|
|
|
|
|
|
|
|
|
Basic
Net
|
|
Diluted
Net
|
|
|||||
|
|
|
Operating
|
|
Gross
|
|
Net
|
|
Income
|
|
Income
|
|
|||||
|
2005
|
|
Revenues
|
|
Profit
(2)
|
|
Income
|
|
Per
Share
|
|
Per
Share
|
|
|||||
|
First
Quarter
|
|
$
|
87,847
|
|
$
|
41,931
|
|
$
|
22,505
|
|
$
|
1.02
|
|
$
|
1.00
|
|
|
Second
Quarter
|
|
|
92,339
|
|
|
45,092
|
|
|
25,260
|
|
|
1.14
|
|
|
1.13
|
|
|
Third
Quarter
|
|
|
109,372
|
|
|
59,880
|
|
|
34,219
|
|
|
1.55
|
|
|
1.52
|
|
|
Fourth
Quarter
|
|
|
115,363
|
|
|
52,754
|
|
|
30,372
|
|
|
1.39
|
|
|
1.35
|
|
|
|
|
$
|
404,921
|
|
$
|
199,657
|
|
$
|
112,356
|
|
$
|
5.10
|
|
$
|
5.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
$
|
57,139
|
|
$
|
20,948
|
|
$
|
10,364
|
|
$
|
0.48
|
|
$
|
0.47
|
|
|
Second
Quarter
|
|
|
64,046
|
|
|
25,591
|
|
|
15,278
|
|
|
0.70
|
|
|
0.68
|
|
|
Third
Quarter
|
|
|
72,904
|
|
|
31,716
|
|
|
18,229
|
|
|
0.83
|
|
|
0.82
|
|
|
Fourth
Quarter (1)
|
|
|
80,431
|
|
|
36,989
|
|
|
25,316
|
|
|
1.15
|
|
|
1.11
|
|
|
|
|
$
|
274,520
|
|
$
|
115,244
|
|
$
|
69,187
|
|
$
|
3.16
|
|
$
|
3.08
|
|
(1)
During the fourth quarter of 2004, the Company recorded a net tax benefit
of
approximately $2.3 million, primarily due to the recognition of deferred
tax
assets related to certain properties and other tax items.
(2)
Information has been revised in 2004 to reflect the Company's change in
allocation of technical labor as disclosed in Note 2.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
19. Subsequent
Events
On
January 27, 2006 the Company announced that it had entered into an agreement
with a private seller to acquire a 50% working interest in natural gas assets
in
the Piceance Basin of western Colorado for approximately $159 million to
increase natural gas reserves and production. The acquisition was funded
under
the Company's existing credit facility. The effective date of the transaction
is
October 1, 2005. The Company purchased 100% interests in Piceance Operating
Company (which owns a 50% working interest in the acquired assets). The Company
will finalize its purchase price allocation after determining the post-closing
adjustments. The transaction closed on February 28, 2006.
In
February 2006, the Company purchased a third drilling rig for approximately
$5
million for use in its Piceance Basin development program.
On
March
1, 2006, the Board of Directors of the Company approved a two-for-one split
of
the Company's Class A Common Stock (Common Stock) and Class B Stock,
subject
to shareholder approval of an increase in authorized shares.The stock split
will
require that shareholders authorize the issuance of new shares at the Company’s
May 17, 2006 annual meeting. Berry's shareholders will be asked to approve
an
increase in the Company's authorized shares of Common Stock to 100 million
from
the current 50 million shares and the Class B Stock to 3.0 million shares
from
1.5 million shares. If approved, Berry’s transfer agent will distribute to each
holder of record as of the close of business on May 17, 2006, one additional
share for every share of stock held. The split will be in the form of a stock
dividend, which will be distributed on June 2, 2006. Berry’s Common Stock should
begin trading on a post-split basis June 5, 2006. Based on shares outstanding
on
March 1, 2006, Berry would have approximately 42.2 million shares of Common
Stock and 1.8 million shares of Class B Stock outstanding following the proposed
stock split.
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)
The
following estimates of proved oil and gas reserves, both developed and
undeveloped, represent interests owned by the Company located solely within
the
United States. Proved reserves represent estimated quantities of crude oil
and
natural gas which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed oil and gas reserves
are the
quantities expected to be recovered through existing wells with existing
equipment and operating methods. Proved undeveloped oil and gas reserves
are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells for which relatively major expenditures are required
for
completion.
Disclosures
of oil and gas reserves which follow are based on estimates prepared by
independent engineering consultants as of December 31, 2005, 2004 and 2003.
Such
estimates are subject to numerous uncertainties inherent in the estimation
of
quantities of proved reserves and in the projection of future rates of
production and the timing of development expenditures. These estimates do
not
include probable or possible reserves. The information provided does not
represent Management's estimate of the Company's expected future cash flows
or
value of proved oil and gas reserves.
BERRY
PETROLEUM COMPANY
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)(Cont'd)
Changes
in estimated reserve quantities
The
net
interest in estimated quantities of proved developed and undeveloped reserves
of
crude oil and natural gas at December 31, 2005, 2004 and 2003, and changes
in
such quantities during each of the years then ended were as follows (in
thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||||||||||||||||||||||
|
|
|
Oil
|
|
Gas
|
|
|
|
Oil
|
|
Gas
|
|
|
|
Oil
|
|
Gas
|
|
|
|
|||||||||||
|
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
|||||||||||
|
Proved
developed and Undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Beginning
of year
|
|
|
105,549
|
25,724
|
109,836
|
|
106,640
|
|
|
19,680
|
|
|
109,920
|
|
|
100,744
|
|
|
5,850
|
|
|
101,719
|
|
|||||||
|
Revision
of previous estimates
|
|
|
(681
|
)
|
4,084
|
-
|
|
2,975
|
|
|
8,246
|
|
|
4,349
|
|
|
(82
|
)
|
|
293
|
|
|
(33
|
)
|
||||||
|
Improved
recovery
|
|
|
753
|
-
|
753
|
|
2,021
|
|
|
-
|
|
|
2,021
|
|
|
1,271
|
|
|
-
|
|
|
1,271
|
|
|||||||
|
Extensions
and discoveries
|
|
|
6,228
|
24,605
|
10,329
|
|
2,736
|
|
|
714
|
|
|
2,855
|
|
|
1,853
|
|
|
2,005
|
|
|
2,187
|
|
|||||||
|
Property
sales
|
|
|
(1,035
|
)
|
-
|
(1,035
|
)
|
|
(127
|
)
|
|
(77
|
)
|
|
(140
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|||||
|
Production
|
|
|
(7,081
|
)
|
(7,919
|
)
|
(8,401
|
)
|
|
(7,044
|
)
|
|
(2,839
|
)
|
|
(7,517
|
)
|
|
(5,827
|
)
|
|
(1,277
|
)
|
|
(6,040
|
)
|
||||
|
Purchase
of reserves in place (1)
|
|
|
-
|
88,817
|
14,803
|
|
132
|
|
|
-
|
|
|
132
|
|
|
8,681
|
|
|
12,809
|
|
|
10,816
|
|
|||||||
|
Royalties
converted to working interest
|
|
|
-
|
-
|
-
|
|
(1,784
|
)
|
|
-
|
|
|
(1,784
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|||||||
|
End
of year
|
|
|
103,733
|
135,311
|
126,285
|
|
105,549
|
|
|
25,724
|
|
|
109,836
|
|
|
106,640
|
|
|
19,680
|
|
|
109,920
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Proved
developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Beginning
of year
|
|
|
78,207
|
20,048
|
81,549
|
|
78,145
|
|
|
12,207
|
|
|
80,180
|
|
|
72,889
|
|
|
3,252
|
|
|
73,431
|
|
|||||||
|
End
of year
|
|
|
78,308
|
70,519
|
90,061
|
|
78,207
|
|
|
20,048
|
|
|
81,549
|
|
|
78,145
|
|
|
12,207
|
|
|
80,180
|
|
|||||||
(1)
Refer to Note 16 to the financial statements.
The
standardized measure has been prepared assuming year end sales prices adjusted
for fixed and determinable contractual price changes, current costs and
statutory tax rates (adjusted for tax credits and other items), and a ten
percent annual discount rate. No deduction has been made for depletion,
depreciation or any indirect costs such as general corporate overhead or
interest expense. Cash outflows for future production and development costs
include cash flows associated with the ultimate settlement of the asset
retirement obligation.
Standardized
measure of discounted future net cash flows from estimated production of
proved
oil and gas reserves (in thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Future
cash inflows
|
|
$
|
6,088,170
|
$
|
3,281,155
|
|
$
|
2,845,767
|
|
|
|
Future
production costs
|
|
|
(2,297,638
|
)
|
|
(1,405,432
|
)
|
|
(1,246,340
|
)
|
|
Future
development costs
|
|
|
(333,722
|
)
|
|
(216,859
|
)
|
|
(198,279
|
)
|
|
Future
income tax expenses
|
|
|
(1,115,516
|
)
|
|
(355,764
|
)
|
|
(324,097
|
)
|
|
Future
net cash flows
|
|
|
2,341,294
|
|
1,303,100
|
|
|
1,077,051
|
|
|
|
10%
annual discount for estimated timing of cash flows
|
|
|
(1,089,914
|
)
|
|
(616,352
|
)
|
|
(548,831
|
)
|
|
Standardized
measure of discounted future net cash flows
|
|
$
|
1,251,380
|
$
|
686,748
|
|
$
|
528,220
|
|
|
|
Average
sales prices at December 31:
|
|
|
|
|
|
|
|
|
||
|
Oil
($/Bbl)
|
|
$
|
48.38
|
$
|
29.49
|
|
$
|
25.77
|
|
|
|
Gas
($/Mcf)
|
|
$
|
7.91
|
$
|
6.61
|
|
$
|
4.94
|
|
|
|
BOE
Price
|
|
$
|
48.21
|
$
|
29.87
|
|
$
|
25.89
|
|
|
BERRY
PETROLEUM COMPANY
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)(Cont'd)
Changes
in standardized measure of discounted future net cash flows from proved oil
and
gas reserves (in thousands):
|
|
2005
|
|
2004
|
|
2003
|
|
||||
|
|
|
|
|
|
|
|
|
|||
|
Standardized
measure - beginning of year
|
|
$
|
686,748
|
$
|
528,220
|
|
$
|
449,857
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Sales
of oil and gas produced, net of production costs
|
|
|
(240,039
|
)
|
|
(144,457
|
)
|
|
(75,143
|
)
|
|
Revisions
to estimates of proved reserves:
|
|
|
|
|
|
|
|
|
||
|
Net
changes in sales prices and production costs
|
|
|
702,867
|
|
190,861
|
|
|
45,292
|
|
|
|
Revisions
of previous quantity estimates
|
|
|
5
|
|
40,419
|
|
|
(229
|
)
|
|
|
Improved
recovery
|
|
|
12,267
|
|
18,787
|
|
|
9,400
|
|
|
|
Extensions
and discoveries
|
|
|
168,291
|
|
26,541
|
|
|
16,171
|
|
|
|
Change
in estimated future development costs
|
|
|
(157,068
|
)
|
|
(56,314
|
)
|
|
(75,841
|
)
|
|
Purchases
of reserves in place
|
|
|
103,150
|
|
962
|
|
|
47,700
|
|
|
|
Sales
of reserves in place
|
|
|
(9,613
|
)
|
|
(1,043
|
)
|
|
-
|
|
|
Development
costs incurred during the period
|
|
|
111,613
|
|
65,971
|
|
|
41,461
|
|
|
|
Accretion
of discount
|
|
|
87,650
|
|
68,312
|
|
|
59,983
|
|
|
|
Income
taxes
|
|
|
(392,886
|
)
|
|
(16,890
|
)
|
|
(8,896
|
)
|
|
Other
|
|
|
178,395
|
|
(21,430
|
)
|
|
18,465
|
|
|
|
Royalties
converted to working interest
|
|
|
-
|
|
(13,191
|
)
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Net
increase (decrease)
|
|
|
564,632
|
|
158,528
|
|
|
78,363
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Standardized
measure - end of year
|
|
$
|
1,251,380
|
$
|
686,748
|
|
$
|
528,220
|
|
|
None.
Evaluation
of Disclosure Controls and Procedures
As
of
December 31, 2005, the Company has carried out an evaluation under the
supervision of, and with the participation of, the Company's Management,
including the Company's Chief Executive Officer and Chief Financial Officer,
of
the effectiveness of the design and operation of the Company's disclosure
controls and procedures pursuant to Rule 13a-15 under the Securities Exchange
Act of 1034, as amended.
Based
on
their evaluation as of December 31, 2005, the Chief Executive Officer and
Chief
Financial Officer of the Company have concluded that the Company’s disclosure
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under
the Securities Exchange Act of 1934) are effective to ensure that the
information required to be disclosed by the Company in the reports that it
files
or submits under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in SEC rules and
forms.
Management’s
Report on Internal Control Over Financial Reporting
Internal
control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f)
promulgated under the Securities Exchange Act of 1934, as amended, as a process
designed by, or under the supervision of, the Company's principal executive
and
principal financial officers, or persons performing similar functions, and
effected by the Company's Board of Directors, Management and other personnel,
to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external reporting purposes
in
accordance with U.S. generally accepted accounting principles and includes
those
policies and procedures that:
· pertain
to the maintenance of records that in reasonable detail accurately and fairly
reflect the transactions and dispositions of the Company's assets;
· provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company
are
being made only in accordance with authorizations of the Company's Management
and Directors; and
· provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the Company's assets that could have a
material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. All internal control systems, no matter
how
well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect
to
financial statement preparation and presentation. Additionally, projections
of
any evaluation of effectiveness to future periods are subject to the risk
that
controls may become inadequate because of changes in conditions, or that
the
degree of compliance with the policies or procedures may
deteriorate.
Management
is responsible for establishing and maintaining adequate internal control
over
financial reporting, as such term is defined in Exchange Act
Rule 13a-15(f). Under the supervision and with the participation of
Management, including the principal executive officer and principal financial
officer, the Company conducted an evaluation of the effectiveness of its
internal control over financial reporting based on the framework in Internal
Control - Integrated Framework issued
by
the Committee of Sponsoring Organizations of the Treadway Commission. Based
on
its evaluation under the framework in Internal
Control - Integrated Framework,
Management concluded that its internal control over financial reporting was
effective as of December 31, 2005.
Management’s
assessment of the effectiveness of the Company's internal control over financial
reporting as of December 31, 2005 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm,
as
stated in their report which is included herein.
Changes
in Internal Control Over Financial Reporting
There
were no changes in the Company's internal control over financial reporting
that
occurred during the three months ended December 31, 2005 that have materially
affected, or are reasonably likely to materially affect, the Company's internal
control over financial reporting. The Company may make changes in its internal
control procedures from time to time in the future.
On
March
1, 2006, the Board of Directors of the Company approved a two-for-one split
of
the Company's Class A Common Stock (Common Stock) and Class B Stock, subject
to
shareholder approval of an increase in authorized shares.The stock split
will
require that shareholders authorize the issuance of new shares at the Company’s
May 17, 2006 annual meeting. Berry's shareholders will be asked to approve
an
increase in the Company's authorized shares of Common Stock to 100 million
from
the current 50 million shares and the Class B Stock to 3.0 million shares
from
1.5 million shares. If approved, Berry’s transfer agent will distribute to each
holder of record as of the close of business on May 17, 2006, one additional
share for every share of stock held. The split will be in the form of a stock
dividend, which will be distributed on June 2, 2006. Berry’s Common Stock should
begin trading on a post-split basis June 5, 2006. Based on shares outstanding
on
March 1, 2006, Berry would have approximately 42.2 million shares of Common
Stock and 1.8 million shares of Class B Stock outstanding following the proposed
stock split.
On
February 28, 2006 the Company completed the acquisition of a 50% working
interest in natural gas assets in the Grand Valley field in the Piceance
Basin
of western Colorado for approximately $159 million. The purchase was funded
under the Company's existing credit facility. Berry is the operator and owns
a
50% working interest in 6,314 gross acres targeting gas in the Williams Fork
section of the Mesaverde formation. Estimated daily production, net to Berry's
interest, is approximately 1 million cubic feet of natural gas per day (MMcf/D)
from three producing wells. The Company internally estimates 330 billion
cubic
feet of proved and probable
reserves,
none of which are included in Berry's 2005 year-end proved reserves of 126
million barrels of oil equivalent (BOE). With this acquisition, the Company's
current estimate of its total proved reserves is over 130 million BOE. Berry
is
increasing its 2006 capital budget by an additional $18 million to $208 million
for 2006 to accelerate the development of this resource. Seven wells are
currently awaiting completion which is expected by April 1, 2006.
On
January 31, 2006 the Company paid cash bonuses to employees related to the
Company's and each individual's performance in 2005. Mr Heinemann was paid
$500,000, Mr. Goehring $185,500, Mr. Duginski $212,000, Mr. Magruder $212,000
and Mr. Crawford $96,300. Effective January 1, 2006 Mr. Heinemann's salary
was increased to $500,000, Mr. Goehring's to $250,000, Mr. Duginski's to
$250,000, Mr. Magruder's to $250,000 and Mr. Crawford's to
$200,000.
Effective
in January 2006 the compensation of the Chairman of the Board, Mr. Martin
H.
Young, Jr., was increased by providing that he be paid the same meeting fees
as
all other directors in addition to the annual retainer of $125,000 and a
special
award of $40,000 was made to Mr. Young in recognition of extraordinary
commitment of time and resources by him on behalf of the Company in 2005.
Mr. Young has elected to receive all compensation paid for his service to
the
Company in the form of Company stock under the terms of the Non-Employee
Director Deferred Compensation Plan.
PART
III
The
information called for by Item 10 is incorporated by reference from information
under the captions “Corporate Governance and Board Matters” and “Compliance with
Section 16(a) of the Securities Exchange Act of 1934” in the Company’s
definitive proxy statement to be filed pursuant to Regulation 14A no later
than
120 days after the close of its fiscal year. Information regarding Executive
Officers is contained in this report in Part I, Item 1
Business.
The
information called for by Item 11 is incorporated by reference from information
under the caption "Executive Compensation" in the Company's definitive proxy
statement to be filed pursuant to Regulation 14A no later than 120 days after
the close of its fiscal year.
The
information called for by Item 12 is incorporated by reference from information
under the captions "Security Ownership of Directors and Management" and
"Principal Shareholders" in the Company's definitive proxy statement to be
filed
pursuant to Regulation 14A no later than 120 days after the close of its
fiscal
year.
The
information called for by Item 13 is incorporated by reference from information
under the caption "Certain Relationships and Related Transactions" in the
Company's definitive proxy statement to be filed pursuant to Regulation 14A
no
later than 120 days after the close of its fiscal year.
The
information called for by Item 14 is incorporated by reference from the
information under the caption “Fees to Independent Accountants for 2005 and
2004” in the Company’s definitive proxy statement to be filed pursuant to
Regulation 14A no later than 120 days after the close of its fiscal
year.
PART
IV
A.
Financial Statements and Schedules
See
Index
to Financial Statements and Supplementary Data in Item 8.
B.
Exhibits
|
Exhibit
No.
|
Description
of Exhibit
|
|
|
|
|
3.1
|
Registrant's
Restated Certificate of Incorporation
|
|
3.2*
|
Registrant's
Restated Bylaws dated July 1, 2005 (filed as Exhibit 3.1 to the
Registrant's Quarterly Report on Form 10-Q for the quarterly period
ended
June 30, 2005, File No. 1-09735)
|
|
4.1*
|
Registrant's
Certificate of Designation, Preferences and Rights of Series B
Junior
Participating Preferred Stock (filed as Exhibit A to the Registrant's
Registration Statement on Form 8-A12B on December 7, 1999, File
No.
778438-99-000016)
|
|
4.2*
|
Rights
Agreement between Registrant and ChaseMellon Shareholder Services,
L.L.C.
dated as of December 8, 1999 (filed by the Registrant on Form 8-A12B
on
December 7, 1999, File No. 778438-99-000016)
|
|
10.1
|
Description
of Cash Bonus Plan of Berry Petroleum Company
|
|
10.2*
|
Form
of Salary Continuation Agreement dated as of December 5, 1997,
by and
between Registrant and selected employees of the Company (filed
as Exhibit
10.3 to the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 1997, File No. 1-9735)
|
|
10.3*
|
Form
of Salary Continuation Agreements dated as of March 20, 1987, as
amended
August 28, 1987, by and between Registrant and selected employees
of the
Company (filed as Exhibit 10.12 to the Registration Statement on
Form S-1
filed on June 7, 1989, File No. 33-29165)
|
|
10.4*
|
Instrument
for Settlement of Claims and Mutual Release by and among Registrant,
Victory Oil Company, the Crail Fund and Victory Holding Company
effective
October 31, 1986 (filed as Exhibit 10.13 to Amendment No. 1 to
the
Registrant's Registration Statement on Form S-4 filed on May 22,
1987,
File No. 33-13240)
|
|
10.5*
|
Credit
Agreement, dated as of June 27, 2005, by and between the Registrant
and
Wells Fargo Bank, N.A. and other financial institutions (filed
as Exhibit
10.1 to the Registrant's Quarterly Report on Form 10-Q for the
quarterly
period ended June 30, 2005, File No. 1-9735)
|
|
10.6
|
First
Amendment to Credit Agreement, dated as of December 15, 2005 by
and
between the Registrant and Wells Fargo Bank, N.A. and other financial
institutions
|
|
10.7*
|
Amended
and Restated 1994 Stock Option Plan (filed as Exhibit 4.1 to the
Registrant’s Registration Statement on Form S-8 filed on August 20, 2002,
File No. 333-98379)
|
|
10.8*
|
Berry
Petroleum Company 2005 Equity Incentive Plan (filed as Exhibit
4.2 to the
Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018)
|
|
10.9*
|
Form
of the Stock Option Agreement, by and between Registrant and selected
employees, directors, and consultants (filed as Exhibit 4.3 to
the
Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018)
|
|
10.10*
|
Form
of the Stock Appreciation Rights Agreement, by and between Registrant
and
selected employees, directors, and consultants (filed as Exhibit
4.4 to
the Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018)"
|
|
10.11*
|
Form
of Stock Award Agreement, by an between Registrant and selected
employees,
directors, and consultants (filed as Exhibit 99.1 on Form 8-k filed
on
December 22, 2005, File No. 1-9735)
|
|
10.12*
|
Crude
oil purchase contract, dated November 14, 2005 between Registrant
and Big
West of California, LLC (filed as Exhibit 99.2 on Form 8-k filed
on
November 22, 2005, File No. 1-9735)
|
|
10.13
|
Non-Employee
Director Deferred Stock and Compensation Plan (as amended effective
January 1, 2006)
|
|
10.14*
|
Employment
Contract dated as of June 16, 2004 by and between the Registrant
and
Robert F. Heinemann (filed as Exhibit 10.1 to the Registrant's
Quarterly
Report on Form 10-Q for the quarter ended June 30, 2004, File No.
1-9735)
|
|
10.15*
|
Salary
Continuation Agreement dated as of June 16, 2004 by and between
the
Registrant and Robert F. Heinemann (filed as Exhibit 10.2 to the
Registrant's Quarterly Report on Form 10-Q for the quarter ended
June 30,
2004, File No. 1-9735)
|
|
10.16*
|
Purchase
and sale agreement between the Registrant and J-W Operating Company
(filed
as Exhibit 99.2 to the Registrant's Current Report on Form 8-K/A
filed on
February 15, 2005, File No. 1-9735)
|
|
10.17
|
Amended
and Restated Purchase and Sale Agreement between Registrant and
Orion
Energy Partners, LP.
|
|
23.1
|
Consent
of PricewaterhouseCoopers LLP, Independent Registered Public Accounting
Firm
|
|
23.2
|
Consent
of DeGolyer and MacNaughton
|
|
31.1
|
Certification
of Chief Executive Officer pursuant to SEC Rule
13(a)-14(a)
|
|
31.2
|
Certification
of Chief Financial Officer pursuant to SEC Rule
13(a)-14(a)
|
|
32.1
|
Certification
of Chief Executive Officer pursuant to Section 1350 of Chapter
63 of Title
18 of the U.S. Code
|
|
32.2
|
Certification
of Chief Financial Officer pursuant to Section 1350 of Chapter
63 of Title
18 of the U.S. Code
|
|
99.1*
|
Form
of Indemnity Agreement of Registrant (filed as Exhibit 99.1 in
Registrant's Annual Report on Form 10-K filed on March 31, 2005,
File No.
1-9735)
|
|
99.2*
|
Form
of "B" Group Trust (filed as Exhibit 28.3 to Amendment No. 1 to
Registrant's Registration Statement on Form S-4 filed on May 22,
1987,
File No. 33-13240)
|
|
*
Incorporated by reference
|
|
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of
1934, the registrant has duly caused this report to be signed on its behalf
by
the undersigned, thereto duly authorized on March 1, 2006.
BERRY
PETROLEUM COMPANY
|
/s/
Robert F. Heinemann
|
/s/
Ralph J. Goehring
|
/s/
Donald A. Dale
|
|
ROBERT
F. HEINEMANN
|
RALPH
J. GOEHRING
|
DONALD
A. DALE
|
|
President,
Chief Executive Officer
|
Executive
Vice President and
|
Controller
|
|
and
Director
|
Chief
Financial Officer
|
(Principal
Accounting Officer)
|
|
|
(Principal
Financial Officer)
|
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has
been
signed below by the following persons on behalf of the registrant and in
the
capacities on the dates so indicated.
|
Name
|
Office
|
Date
|
|
|
|
|
|
/s/
Martin H. Young, Jr.
|
Chairman
of the Board,
|
March
1, 2006
|
|
Martin
H. Young, Jr.
|
Director
|
|
|
/s/
Robert F. Heinemann
|
President,
Chief Executive Officer
|
March
1, 2006
|
|
Robert
F. Heinemann
|
and
Director
|
|
|
|
|
|
|
/s/
William F. Berry
|
Director
|
March
1, 2006
|
|
William
F. Berry
|
|
|
|
|
|
|
|
/s/
Joseph H. Bryant
|
Director
|
March
1, 2006
|
|
Joseph
H. Bryant
|
|
|
|
|
|
|
|
/s/
Ralph B. Busch, III
|
Director
|
March
1, 2006
|
|
Ralph
B. Busch, III
|
|
|
|
|
|
|
|
/s/
William E. Bush, Jr.
|
Director
|
March
1, 2006
|
|
William
E. Bush, Jr.
|
|
|
|
|
|
|
|
/s/
Stephen L. Cropper
|
Director
|
March
1, 2006
|
|
Stephen
L. Cropper
|
|
|
|
|
|
|
|
/s/
J. Herbert Gaul, Jr.
|
Director
|
March
1, 2006
|
|
J.
Herbert Gaul, Jr.
|
|
|
|
|
|
|
|
/s/
Thomas J. Jamieson
|
Director
|
March
1, 2006
|
|
Thomas
J. Jamieson
|
|
|
|
/s/
J. Frank Keller
|
Director
|
March
1, 2006
|
|
J.
Frank Keller
|
|
|
|
|
|
|
71
Exhibit
3.1
RESTATED
CERTIFICATE
OF INCORPORATION
OF
BERRY
PETROLEUM COMPANY
Reflecting
all amendments as of December 31, 2005
The
undersigned, for the purposes of restating the Certificate of Incorporation
of
Berry Petroleum Company, originally filed with the Secretary of State of the
State of Delaware on September 30, 1985, do execute this Restated Certificate
of
Incorporation pursuant to Section
245 of the Delaware General Corporation Law of the
State of
Delaware (“General Corporation Law”) and do hereby certify as
follows:
First:
The name
of the Corporation is Berry Petroleum Company.
Second:
The
address of the registered office of the Corporation in the State of Delaware
is
The Corporation Trust
Center, 1209 Orange Street, Wilmington, Delaware 19807,
County
of New Castle. The name of the registered agent of the Corporation at such
address is
The.
Corporation Trust Company.
Third: The
purpose of the Corporation is to engage in any lawful act or activity for which
corporations may be organized under the General Corporation Law of the State
of
Delaware.
Fourth:
(a)
The
total
number of shares of stock which the Corporation shall have authority to issue
is
fifty-three million five hundred thousand shares, consisting of fifty million
shares of Class A Common Stock (“Class A Stock”) having par value of $.01 per
share, one million five hundred thousand shares of Class B Stock having par
value of $.01 per share, and two million shares of Preferred Stock having a
par
value of $.01 per share. The Class A Stock and Class B Stock are sometimes
collectively referred to herein as the “Capital Stock.”
(b)
Subject to all of the powers, preferences, and rights of Preferred Stock or
any
series thereof, dividends may be paid on the Capital Stock if, as, and when
declared by the Board of Directors, out of any funds of the Corporation legally
available for the payment of dividends. Each share of Capital Stock shall
participate equally with each other, without preference or distinction, as
to
the payments of dividends (including stock dividends) and, subject to Paragraph
(g) of this Article Fourth, other distributions made with respect to the Capital
Stock.
(c) Each
share of Class A Stock shall be entitled to one vote and each share of Class
B
Stock shall be entitled to 95% of one vote on all matters upon which the Capital
Stock is entitled to vote. The Class A Stock and Class B Stock shall vote as
a
single class on all matters upon which the Capital Stock is entitled to
vote.
(d) At
all
elections
of
directors of the Corporation,
each stockholder shall be entitled to as many votes
as
shall equal the number of votes which (except for
this
provision as to cumulative voting) he would be entitled to cast for the election
of a director with respect
to his shares of stock multiplied by the number of directors
to be elected, and he may cast all of such votes
for a
single director or may distribute them among the number to be voted for, or
for
any two or more of them as he may see fit.
(e) Each
share of Class B Stock shall be convertible,
at the option of the holder thereof, into one share
of
fully paid and nonassessable Class A Stock at any time
after December 31, 1990 or, prior to January 1, 1991,
during
the period commencing as of the date of the first announcement of and ending
as
of the date of the consummation of any of the following (provided that each
such
period shall in no event be less than 10 days):
(i) any
proposed public offering of the Corporation’s Class A Stock;
(ii) any
proposed merger, consolidation or other business reorganization or combination
of the Corporation with or into any other corporation or entity (other than
a
transaction in which the Corporation is the surviving entity and the Corporation
does not become a subsidiary of another corporation);
(iii) any
proposed sale, lease, exchange, or other transfer or disposition of all or
any
substantial part of the assets of the Corporation or any of its
subsidiaries;
(iv) any
offer
(pursuant to an offer to purchase, a solicitation of an offer to sell, or an
invitation to make an offer to sell) or agreement, or a combination thereof,
to
acquire directly or indirectly shares of Class A Stock for cash, securities,
or
any other consideration where the shares which are the subject of the offer
or
agreement or the combination thereof, together with the offeror’s presently
beneficially owned shares (calculated pursuant to Article Eighth, Paragraph
(b))
will in the aggregate exceed 20% of the outstanding shares of Class A
Stocks;
or
(v) in
the
event that the liquidation preferences provided for in subparagraphs (g)(1)(i)
and (ii) below shall cease to be applicable by virtue of the provisions of
subparagraph (g)(1)(iv) below.
1
Exhibit
3.1
Before
any holder of Class B Stock shall be entitled to convert the same into shares
of
Class A Stock, the holder shall surrender the certificate or certificates
therefor, duly endorsed at the principal executive office of the Corporation
or
of any transfer agent and shall give written notice to the Corporation at such
office that the holder elects to convert the same. The Corporation shall, as
soon as practicable thereafter, issue and deliver at such office to such holder
of Class B Stock a certificate or certificates for the number of shares of
Capital Stock to which the holder shall be entitled as set forth above. Such
conversion shall be deemed for all purposes to have been made, if made after
December 31, 1990, immediately prior to the close of business on the date of
such surrender of the shares of Class B Stock to be converted and, if made
before January 1, 1991, upon the commencement of the conversion period referred
to above, and the person or persons entitled to receive the shares of Class
A
Stock issuable upon such conversion shall be treated for all purposes as the
record holder or holders of such shares of Class A Stock on such
date.
If
the
Corporation shall subdivide its outstanding
shares of Class A Stock into a larger number
of
shares or shall combine its outstanding shares of Class
A
Stock into a small number of shares, the shares of
Class B
Stock then outstanding shall likewise be subdivided or combined.
(f)
(1) If
at any
time there is proposed to
be
presented to the stockholders of the Corporation for
their
approval (by vote at a meeting or by written consent) any matter (including
without limitation a merger, sale of assets or reorganization involving the
Corporation) the approval of which under then applicable law would require
the
vote or consent of the holders of Class A Stock and Class B Stock as separate
classes, and the
application of subparagraph (g)(1)(iv) below does not alter
such class vote or consent requirement in such a way
as to
permit such matter to be duly approved by the holders
of Class A Stock and Class B Stock voting together as
a
single class, then, in such event and effective as of
the
applicable record date for determination of stockholders entitled to vote upon
or consent to such matter, each outstanding share of Class B Stock shall be
converted automatically into one share of Class A Stock; provided, however,
that
the provisions of this subparagraph (f)(1) shall not apply to any proposal
to
amend this Certificate of Incorporation if the amendment would increase or
decrease
the
aggregate number of authorized shares of Class A Stock or Class B Stock,
increase or decrease the par value of
Class
A
Stock or Class
B
Stock, or alter or change the powers, preferences or
special rights of Class A Stock or Class B Stock so as
to
affect them adversely.
(2) Upon
the
occurrence of the event specified in subparagraph (f)(1) above, the outstanding
shares of Class B Stock shall be converted automatically without any further
action by the holders of such shares and
whether
or not the certificates representing such shares
are surrendered to the Corporation or its transfer
agent;
provided, however, that the Corporation shall not be obligated to issue
certificates evidencing the shares of
Class
A Stock issuable upon such conversion unless the
certificates evidencing such shares of Class B Stock are either
delivered to the Corporation or its transfer agent as
provided below, or the holder notifies the Corporation
or its
transfer agent that such certificates have been lost, stolen or destroyed and
executes an agreement satisfactory to the Corporation to indemnify
the
Corporation from any loss incurred by it in connection with such certificates.
Upon the occurrence of such automatic
conversion of the Class B Stock, the holders of
Class B
Stock shall surrender the certificates representing
such shares at the office of the Corporation
or any
transfer agent for the Class B Stock or Class A Stock. Thereupon, there shall
be
issued and delivered to such holder promptly at such office and in his name
as
shown on such surrendered certificate or certificates, a certificate or
certificates for the number of shares of Class A Stock into which the shares
of
Class B Stock surrendered were convertible on the date on which such automatic
conversion
occurred.
(g) (1) In
the
event of any liquidation, dissolution, or winding up of the Corporation, either
voluntary or involuntary, the assets and funds of the Corporation
available for distribution to the stockholders
of the
Corporation shall be distributed as follows:
(i) The
holders of Class B Stock shall be
entitled to receive, prior and in preference to any distribution
of any assets or funds of the Corporation
to the
holders of Class A Stock, an amount equal to $1.00 per share for each share
of
Class B Stock then outstanding
(subject to adjustment in the event of any stock
dividends, subdivisions, or combinations so that
the
aggregate liquidation preference of all shares of Class
B
Stock issued and outstanding immediately prior
to
any
such
stock dividend, subdivision, or combination shall be and remain the same
immediately thereafter), plus an amount equal to any dividends declared but
unpaid on the Class B Stock. If the assets and funds of the Corporation
available for distribution to the holders of Class B Stock of the Corporation
shall be insufficient to permit the payment of the full preferential amount
set
forth above, then all of the assets and funds of the Corporation available
for
distribution to the holders of Class B Stock shall be distributed to the holders
of Class B Stock pro rata based on their holdings of Class B Stock.
(ii) After
distribution to the holders of Class B Stock of the amounts set forth in
subparagraph (g)(1)(i) above, the holders of Class A Stock shall be entitled
to
receive, prior and in preference to any additional distribution of any assets
or
funds of the Corporation to the holders of Class B Stock and Class A Stock
as
provided in paragraph (g)(1)(iii) below, an amount equal to $1.00 per share
for
each share of Class A Stock then outstanding
(subject to adjustment in the event of any stock
dividends, subdivisions, or combinations so that
the
aggregate liquidation preference of all shares of Class
A
Stock issued and outstanding immediately prior
to any
such stock dividend, subdivision, or combination shall be and remain the same
immediately thereafter), plus an amount equal to any dividends declared but
unpaid on the Class A Stock. If the assets and funds of the Corporation
available for distribution
to the holders of the Class A Stock shall
be
insufficient to permit the full payment of the preferential amount set forth
in
this subparagraph (g)(1)(ii), then all of the assets and funds available for
distribution to the holders of Capital Stock, after payment to the holders
of
Class B Stock of the preferential payment set forth in subparagraph (g)(1)(i).above,
shall be distributed to the holders of
Class
A Stock pro rata based on their holdings of
Class A
Stock.
(iii) After
distribution of the amounts set forth in subparagraphs(g)(1)(i) and (ii) above,
the remaining assets and funds of the Corporation available for distribution
to
the holders of Class A Stock and Class B Stock shall be distributed to the
holders of shares of Class A Stock and Class B Stock pro
rata
on the basis of the total number of shares of Class
A
Stock and Class B Stock outstanding with each share
of
Class A Stock and Class B Stock being treated equally.
2
Exhibit
3.1
(iv) Notwithstanding
the provisions of subparagraphs
(g)(1)(i) and (ii) above, if at any time
there is
proposed to be presented to the stockholders of the Corporation for their
approval (by vote at a meeting or by written consent) any matter (including
without limitation a merger, sale of assets or reorganization
involving the Corporation) the approval
of which
under then applicable law would require the vote or consent of the holders
of
Class A Stock and Class
B
Stock as separate classes, but such class vote
or
consent would not be so required if the liquidation preferences provided for
in
subparagraphs (g)(1)(i) and (ii) were not applicable, then, in such event and
effective on and after the applicable record date for determination
of stockholders entitled to vote upon or
consent
to such matter, the liquidation preferences provided
for in subparagraphs (g)(1)(i) and (ii) above
shall
cease to be applicable and the provisions of subparagraph (g)(1)(iii) shall
thereafter govern all distributions to stockholders in the event of any
liquidation, dissolution, or winding up; provided, however, that the provisions
of
this
subparagraph
(g)(1)(iv) shall not apply to any proposal to amend this Certificate of
Incorporation if the amendment would increase or decrease the aggregate number
of authorized shares of Class A Stock or Class B Stock, increase
or decrease the par value of Class A Stock or
Class B
Stock, or alter or change the powers, preferences
or special rights of Class
A
Stock or Class B Stock so as to affect them adversely.
(2)
A
merger, consolidation, or other business reorganization or combination of the
Corporation with or into any other corporation or entity in which the
Corporation shall not survive or shall become a subsidiary of
another corporation or entity,
or a sale, exchange, lease, or other transfer or disposition of all or
substantially
all of the assets of the Corporation, shall not
be
deemed to be a liquidation, dissolution and winding
up for
the purpose of this paragraph (g).
(3)
If
any of the assets of the Corporation
are to be distributed other than in
cash
under
this
paragraph (g), then the Board of Directors of the Corporation shall
promptly
engage competent independent appraisers to determine the value of the assets
to
be distributed to the holders of Stock.
(h)
The
Board of Directors is authorized, subject to limitations prescribed by law
and
the provisions of this Article Fourth, to provide
for the
issuance of the shares of Preferred Stock in one or more series, and by filing
a
certificate pursuant to the applicable
law of the State of Delaware, to establish from
time
to
time the number of shares
to
be
included in each
such
series, and to fix the voting to be included in each
such
series, and to fix the voting powers, designations, preferences
and relative, participating, optional or other
rights,
if any, or the qualifications, limitations or restrictions thereof, if any,
of
the shares of each such series. The authority of the Board of Directors with
respect to each series shall include, but not be limited to, determination
of
the following:
(i) The
number of shares constituting that series and the distinctive designation
of
that
series;
(ii) The
dividend rate on the shares of that series, whether dividends shall be
cumulative and,
if
so, from which date or dates, and the relative rights
of
priority, if any, of payment of dividends on
shares
of that series;
(iii) Whether
that series shall have voting rights in addition to the voting rights
provided
by law and, if so, the terms of such voting
rights;
(iv) Whether
that series shall have conversion privileges, and, if so, the terms and
conditions
of such conversion, including
provision for
adjustment of the conversion rate in such events as the Board of Directors
shall
determine;
(v) Whether
or not the shares of that series
shall be redeemable, and, if so, the terms and conditions
of such redemption,
including the date or dates upon or after which they shall
be
redeemable,
and the amount per share payable in case of redemption, which
amount may vary
under different
redemption dates;
(vi) Whether
that series shall have a sinking
fund for the redemption or purchase of shares
of the
series, and, if so, the terms and amount of such sinking fund;
(vii) The
rights of the shares of that series in
the
event
of
voluntary or involuntary liquidation, dissolution or winding up of the
Corporation, and
the
relative rights of priority, if any,
of
payment of shares of that series; and
(viii) Any
other
voting powers, designations, preferences, rights and qualifications, limitations
or restrictions of that series, including those dependent upon facts
ascertainable outside the resolution or resolutions adopted by the Board of
Directors providing for the issue of such
series,
provided that the manner in which facts shall operate upon the voting powers,
designations, preferences, rights
and qualifications, limitations or restrictions
of such
series is clearly and expressly set forth in the resolution or resolutions
adopted by the Board of Directors providing for the issue of such
series.
The
number of authorized shares of Preferred Stock may be increased or decreased
(but not below the number of shares thereof then outstanding) by the affirmative
vote of the holders of a majority of the outstanding shares of the Corporation
entitled to vote thereon.
Fifth: The
business and affairs of the Corporation shall be managed by or under the
direction of the Board of Directors. The directors need not be elected by ballot
unless required by the bylaws of the Corporation.
3
Exhibit
3.1
Sixth: The
number of the directors of the Corporation shall be fixed from time to time
by,
or in the manner provided in, the bylaws and may be increased or decreased
as
therein provided, but the number thereof shall not be more than twelve or
less
than nine; provided, however, that at any time the number of stockholders
of the
Corporation shall be three or less, the number thereof shall not be more
than
twelve or less than three.
Seventh: In
furtherance and not in limitation of the powers conferred by the laws of the
State of Delaware, the Board of Directors is expressly authorized to adopt,
amend or repeal the bylaws. The bylaws may be adopted, amended or repealed
by
the stockholders of the Corporation only by the affirmative vote of the holders
of not less than 66-2/3% of the combined voting power of the outstanding shares
of the Corporation entitled to vote thereon.
Eighth:
(a)
Except
as
set forth in paragraph (d) of this Article Eighth, the affirmative vote of
the
holders of at least 66-2/3% of the combined voting power of the outstanding
shares of the Corporation entitled to vote in the election of directors shall
be
required to effect or validate:
(1) any
merger, consolidation or other business reorganization or combination of the
Corporation or any of its subsidiaries with or into any other
corporation;
(2) any
sale,
lease, exchange or other disposition of all or any substantial part of the
assets of the Corporation or any of its subsidiaries to any other corporation,
person or other entity; or
(3) any
sale,
lease, exchange or other disposition to the Corporation or any of its
subsidiaries of any assets, cash securities or other property of any other
corporation, person or other entity (except assets, cash, securities or other
property having an aggregate fair market value of less than $1,000,000) in
exchange for voting securities (or securities convertible into voting securities
or options, warrants, or rights to acquire voting securities or securities
convertible into voting securities) of the Corporation or any of its
subsidiaries, if, as of the record date for the determination of stockholders
entitled to notice thereof and to vote thereon, such other corporation, person
or entity which is party to such a transaction is the beneficial owner, directly
or indirectly of 5% or more of the combined voting power of the outstanding
shares of the Corporation entitled to vote in elections of directors. Such
affirmative vote shall be in addition to any vote of the holders of the shares
of the Corporation otherwise required by law, this Certificate of Incorporation
or any agreement between the Corporation and any national securities
exchange.
(b) For
purposes of Article Fourth, Paragraph (e)(iv) and this Article Eighth, any
corporation, person or other entity shall be deemed to be the beneficial owner
of any shares of the Corporation which:
(1) it
owns
directly, whether or not of record;
(2) it
has
the right to acquire pursuant to any agreement or understanding or upon the
exercise of conversion rights, warrants or options or otherwise;
(3) are
beneficially owned, directly or indirectly (including shares deemed to be owned
through application of clause (2) above), by an “affiliate” or “associate” as
those terms are defined in Rule 12b-2 of the General Rules and Regulations
under
the Securities Exchange Act of 1934 as in effect on January 1, 1985;
or
(4) are
beneficially owned, directly or indirectly (including shares deemed owned
through application of clause (2) above), by any other corporation, person
or
entity with which it or its “affiliate” or “associate” has any agreement or
arrangement or understanding for the purpose of acquiring, holding, voting
or
disposing of shares of the Corporation. For the purpose of determining whether
a
corporation, person or entity is the beneficial owner of 5% or more of the
combined voting power of the outstanding shares of the Corporation entitled
to
vote in elections of directors, the outstanding shares of the Corporation shall
include shares not in fact outstanding but deemed owned through the application
of clauses (b)(2), (3) and (4) above, but shall not include any other shares
which may be issuable pursuant to any agreement or upon the exercise of
conversion rights, warrants or options or otherwise.
(c) The
Board
of-Directors shall have the power and duty to determine for the purposes of
this
Article Eighth, on the basis of information known to the Corporation
whether:
(1) Such
other corporation, person or other entity beneficially owns more than 5% or
more
of the combined voting power of the outstanding shares of the Corporation
entitled to vote in the election of directors;
(2) A
corporation, person or other entity is an “affiliate” or “associate” (as defined
in paragraph (b) above) of another; and
(3) The
assets, cash, securities or other property being acquired by the Corporation,
or
any subsidiary thereof, have an aggregate fair market value of less than
$1,000,000.
4
Exhibit
3.1
Any
such
determination shall be conclusive and binding for all purposes of this Article
Eighth.
(d) The
provisions of this Article Eighth shall not apply to any transaction described
in clauses (1), (2) or (3) of paragraph (a) above if:
(1) The
Board
of Directors of the Corporation has approved such transaction prior to the
time
that the other party thereto shall have become the beneficial owner of more
than
5% of the combined voting power of the. outstanding shares of the Corporation
entitled to vote in the election of directors; or
(2) A
majority of the outstanding shares of all classes of stock entitled to vote
in
the election of directors of such other corporation, or a majority of the equity
interest in any such other person or entity, is owned of record or beneficially,
directly or indirectly, by the Corporation.
Ninth:
To the
fullest extent permitted by the Delaware General Corporation Law, a director
of
this Corporation shall not be liable to the Corporation or to its stockholders
for monetary damages for breach of fiduciary duty as director.
Tenth:
The
Corporation reserves the right to amend and repeal any provision contained
in
this Certificate of Incorporation in the manner prescribed by the laws of the
State of Delaware. Notwithstanding any other provision of this Certificate
of
Incorporation, the affirmative vote of the holders of at least 66-2/3% of the
combined voting power of the outstanding shares of the Corporation entitled
to
vote thereon shall be required to amend or repeal, or to adopt any provision
inconsistent with, this Article Tenth, Paragraph (d) of Article Fourth, or
Articles Sixth, Seventh, Eighth, or Ninth of this Certificate of
Incorporation.
IN
WITNESS WHEREOF, the undersigned hereby certify that this Restated Certificate
of Incorporation has been approved by the vote of the Directors of the
Corporation in accordance with Section 245(b) of the General Corporation Law
of
the State of Delaware; that the foregoing Restated Certificate of Incorporation
restates in its entirety the provisions of the Corporation’s Certificate of
Incorporation filed on September 30, 1985, as previously amended; and hereby
execute and acknowledge the foregoing Restated Certificate of Incorporation
on
this 16th day of February, 2006.
| /s/ Shawn M. Canaday | /s/ Ralph J. Goehring | ||
|
|
|
||
| Name:
Shawn M.
Canaday Title: Assistant Secretary |
Name:
Ralph J.
Goehring Title: Executive Vice-President and Chief Financial Officer |
5
Exhibit
10.1
DESCRIPTION
OF THE SHORT-TERM CASH INVENTIVE PLAN (BONUS)
Annual
cash incentive awards, which are designed to provide short-term performance
incentives, are made to employees to recognize and reward corporate and
individual performance. The plan in effect provides an annual incentive fund
of
up to 3.5% of the Company's annual net income, with certain adjustments,
to
potentially any and all employees upon achievement of the Company’s growth and
profitability goals.
Annually,
Management and the Board will set specific targets to be achieved which will
determine the cash payment as a whole and then to each eligible employee
based
on a formula. There shall be specific targets established for each of the
following: net income, production, operating expenditures, reserve additions,
and finding and development costs. The Board retains the flexibility to adjust
various items to assure compliance with the intent of the cash incentive
awards.
All annual cash bonuses for executives are approved by the Compensation
Committee and the Board of Directors.
1
Exhibit
10.6
[EXECUTION]
FIRST
AMENDMENT TO CREDIT AGREEMENT
THIS
FIRST AMENDMENT TO CREDIT AGREEMENT (herein called the “Amendment”) made as of
December 15, 2005 by and among BERRY PETROLEUM COMPANY, a Delaware corporation
(“Borrower”), WELLS FARGO BANK, NATIONAL ASSOCIATION, individually and as
Administrative Agent (“Agent”), and the Lenders party to the Original Agreement
defined below (“Lenders”).
W
I T N E
S S E T H:
WHEREAS,
Borrower, Agent and Lenders entered into that certain Credit Agreement dated
as
of June 27, 2005 (the “Original Agreement”), for the purpose and consideration
therein expressed, whereby Lenders became obligated to make loans to Borrower
as
therein provided; and
WHEREAS,
Borrower, Agent and Lenders desire to amend the Original Agreement as set forth
herein;
NOW,
THEREFORE, in consideration of the premises and the mutual covenants and
agreements contained herein and in the Original Agreement, in consideration
of
the loans which may hereafter be made by Lenders to Borrower, and for other
good
and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto do hereby agree as follows:
ARTICLE
I.
DEFINITIONS
AND REFERENCES
Section
1.1. Terms
Defined in the Original Agreement.
Unless
the context otherwise requires or unless otherwise expressly defined herein,
the
terms defined in the Original Agreement shall have the same meanings whenever
used in this Amendment.
Section
1.2. Other
Defined Terms.
Unless
the context otherwise requires, the following terms when used in this Amendment
shall have the meanings assigned to them in this Section 1.2.
“Amendment” means this First Amendment to Credit Agreement.
“Credit Agreement” means the Original Agreement as amended hereby.
“Original
Certificate” means the original Omnibus Certificate of Borrower dated as of
June 27, 2005.
ARTICLE
II.
AMENDMENTS
TO ORIGINAL AGREEMENT
Section
2.1. Defined
Terms.
The
definition of “Current Assets” in Section 1.1 of the Original Agreement is
hereby amended in its entirety to read as follows:
“'Current
Assets'
means
the sum of the current assets of Borrower and its Consolidated Subsidiaries
at
such time, plus the Availability at such time in an amount not to exceed
$50,000,000, but excluding, for purposes of this definition any non-cash gains
for any Hedging Contract resulting from the requirements of SFAS 133 at such
time.”
1
Exhibit
10.6
ARTICLE
III.
CONDITIONS
OF EFFECTIVENESS
Section
3.1. Effective
Date.
This
Amendment shall become effective as of the date first above written when, and
only when, (i) Agent shall have received, at Agent's office, a counterpart
of
this Amendment executed and delivered by Borrower and Majority Lenders and
(ii)
Agent shall have additionally received all of the following documents, each
document (unless otherwise indicated) being dated the date of receipt thereof
by
Agent, duly authorized, executed and delivered, and in form and substance
satisfactory to Agent:
(a)
Officer's
Certificate and Supporting Documents.
Agent
shall have received (i) a certificate of the Secretary and the President or
Chief Financial Officer of Borrower certifying (A) that all of the
representations and warranties set forth in Article IV hereof are true and
correct and no Default exists, (B) that attached to the Original Certificate
is
a true and complete copy of resolutions adopted by the Board of Directors of
Borrower authorizing the execution, delivery and performance of this Amendment
and (C)
as to
the names and true signatures of the officers of Borrower authorized to sign
this Amendment, and (ii) such supporting documents as Agent may reasonably
request.
(b)
Borrower shall have paid, in connection with such Loan Documents, all recording,
handling, amendment and other fees required to be paid to Agent pursuant to
any
Loan Documents.
(c)
Borrower shall have paid, in connection with such Loan Documents, all other
fees
and reimbursements to be paid to Agent pursuant to any Loan Documents, or
otherwise due Agent and including fees and disbursements of Agent's attorneys.
ARTICLE
IV.
REPRESENTATIONS
AND WARRANTIES
Section
4.1. Representations
and Warranties of Borrower.
In
order to induce each Lender to enter into this Amendment, Borrower represents
and warrants to each Lender that:
(a)
The
representations and warranties contained in Article V of the Original Agreement
are true and correct at and as of the time of the effectiveness hereof, except
to the extent that the facts on which such representations and warranties are
based have been changed by the extension of credit under the Credit Agreement
except to the extent such representations and warranties specifically refer
to
an earlier date, in which case they are true and correct as of such earlier
date.
(b)
Borrower is duly authorized to execute and deliver this Amendment and is and
will continue to be duly authorized to borrow monies and to perform its
obligations under the Credit Agreement. Borrower has duly taken all corporate
action necessary to authorize the execution and delivery of this Amendment
and
to authorize the performance of the obligations of Borrower hereunder.
(c)
The
execution and delivery by Borrower of this Amendment, the performance by
Borrower of its obligations hereunder and the consummation of the transactions
contemplated hereby and thereby do not and will not conflict with any provision
of law, statute, rule or regulation or of the certificate of incorporation
and
bylaws of Borrower, or of any material agreement, judgment, license, order
or
permit applicable to or binding upon Borrower, or result in the creation of
any
lien, charge or encumbrance upon any assets or properties of Borrower. Except
for those which have been obtained, no consent, approval, authorization or
order
of any court or governmental authority or third party is required in connection
with the execution and delivery by Borrower of this Amendment or to consummate
the transactions contemplated hereby and thereby.
(d)
When
duly executed and delivered, this Amendment and the Credit Agreement will be
a
legal and binding obligation of Borrower, enforceable in accordance with its
terms, except as limited by bankruptcy, insolvency or similar laws of general
application relating to the enforcement of creditors' rights and by equitable
principles of general application.
(e)
The
audited annual Consolidated financial statements of Borrower dated as of
December 31, 2004 and the unaudited quarterly Consolidated financial statements
of Borrower dated as of September 30, 2005 fairly present the Consolidated
financial position at such dates and the Consolidated statement of operations
and the changes in Consolidated financial position for the periods ending on
such dates for Borrower. Copies of such financial statements have heretofore
been delivered to each Lender. Since such dates no material adverse change
has
occurred in the financial condition or businesses or in the Consolidated
financial condition or businesses of Borrower.
2
Exhibit
10.6
ARTICLE
V.
MISCELLANEOUS
Section
5.1. Ratification
of Agreements.
The
Original Agreement as hereby amended is hereby ratified and confirmed in all
respects. The Loan Documents, as they may be amended or affected by this
Amendment, are hereby ratified and confirmed in all respects. Any reference
to
the Credit Agreement in any Loan Document shall be deemed to be a reference
to
the Original Agreement as hereby amended. The execution, delivery and
effectiveness of this Amendment shall not, except as expressly provided herein
or therein, operate as a waiver of any right, power or remedy of Lenders under
the Credit Agreement, the Notes, or any other Loan Document nor constitute
a
waiver of any provision of the Credit Agreement, the Notes or any other Loan
Document.
Section
5.2. Survival
of Agreements.
All
representations, warranties, covenants and agreements of Borrower herein shall
survive the execution and delivery of this Amendment and the performance hereof,
including without limitation the making or granting of the Loans, and shall
further survive until all of the Obligations are paid in full. All statements
and agreements contained in any certificate or instrument delivered by Borrower
any Related Person/Restricted Person hereunder or under the Credit Agreement
to
any Lender shall be deemed to constitute representations and warranties by,
and/or agreements and covenants of, Borrower under this Amendment and under
the
Credit Agreement.
Section
5.3. Loan
Documents.
This
Amendment is a Loan Document, and all provisions in the Credit Agreement
pertaining to Loan Documents apply hereto and thereto.
Section
5.4. Governing
Law.
This
Amendment shall be deemed a contract made under the laws of the State of
California and shall be construed and enforced in accordance with and governed
by the laws of the State of California and the laws of the United States of
America, without regard to principles of conflicts of law.
Section
5.5. Counterparts;
Fax.
This
Amendment may be separately executed in counterparts and by the different
parties hereto in separate counterparts, each of which when so executed shall
be
deemed to constitute one and the same Amendment. This Amendment may be validly
executed by facsimile or other electronic transmission.
THIS
AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN
THE
PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS,
OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL
AGREEMENTS OF THE PARTIES.
[The
remainder of this page has been intentionally left blank.]
3
Exhibit
10.6
IN
WITNESS WHEREOF, this Amendment is executed as of the date first above written.
BERRY
PETROLEUM CORPORATION,
as
Borrower
By:
Ralph
J. Goehring Executive
Executive
Vice President and Chief Financial Officer
WELLS
FARGO BANK, NATIONAL ASSOCIATION,
as
Administrative Agent, LC Issuer and a Lender
By:
Guy
C. Evangelista
Vice
President
JPMORGAN
CHASE BANK, N.A.,
as a
Lender
By:
Jo
Linda Papadakis
Vice
President
BANK
OF SCOTLAND,
as a
Lender
By: Karen
Weich
Assistant
Vice Preside
BNP
PARIBAS,
as a
Lender
By:
Brian
M. Malone
Managing
Director
By:
Polly
Schott
Vice
President
CITIBANK
(WEST), FSB,
as a
Lender
By: Gai
Sherman
VP/Credit
Relationship Mgr.
COMERICA
BANK,
as a
Lender
By:
Juli
Bieser
Vice
President
MIDFIRST
BANK,
as a
Lender
By: Shawn
D. Brewer
Vice
President
SOCIETE
GENERALE,
as a
Lender
By:
Josh
Rogers
Vice
President
UNION
BANK OF CALIFORNIA, N.A.,
as a
Lender
By:
Dustin Gaspari
Vice
President
5
Exhibit
10.13
BERRY
PETROLEUM COMPANY
NON-EMPLOYEE
DIRECTOR DEFERRED
STOCK AND COMPENSATION PLAN
(as
amended effective January 1, 2006)
Section
1. Establishment
of Plan; Purpose. The
Berry Petroleum Company Non-Employee Director Deferred Stock and Compensation
Plan (the “Plan”) is hereby established to permit Eligible Directors, in
recognition of their contributions to the Company (a) to receive Shares in
lieu
of Compensation and (b) to defer recognition of their Compensation in the manner
described below. The Plan is intended to enable the Company to attract, retain
and motivate qualified directors and to enhance the long-term mutuality of
interest between Directors and stockholders of the Company.
Section
2. Definitions. When
used in this Plan, the following terms shall have the definitions set forth
in
this Section:
2.1. “Accounts”
shall mean an Eligible Director’s Stock Unit Account and Interest
Account.
2.2. “Board
of
Directors” shall mean the Board of Directors of the Company.
2.3. “Committee”
shall mean the Compensation Committee of the Board of Directors or such other
committee of the Board as the Board shall designate from time to
time.
2.4. “Company”
shall mean Berry Petroleum Company, a Delaware corporation.
2.5. “Compensation”
shall mean (a) the fee earned by an Eligible Director for service as a Director;
(b) the fee, if any, earned by an Eligible Director for service as a member
of a
committee of the Board of Directors; and (c) the fee earned by an Eligible
Director for (i) attendance at meetings of the Board of Directors and (ii)
attendance at meetings of committees. All Compensation earned by an Eligible
Director for the services identified in subsections (a), (b) and (c) above,
shall be deemed earned by an Eligible Director and credited to the designated
Accounts on the last trading day of the fiscal quarter in which such service
was
provided.
2.6. “Director”
shall mean any member of the Board of Directors, whether or not such member
is
an Eligible Director.
2.7. “Effective
Date” shall mean the date on which the Plan is approved by the stockholders of
the Company.
2.8. “Eligible
Director” shall mean a member of the Board of Directors who is not an employee
of the Company.
2.9. “Exchange
Act” shall mean the Securities Exchange Act of 1934, as amended.
2.10. “Fair
Market Value” shall mean the closing price or the last sale (as reported by the
New York Stock Exchange) of a Share on the last trading day of the fiscal
quarter as required by Section 5.4(a) or any other reasonable basis using actual
transactions of such Shares as reported and as shall be consistently applied
by
the Committee.
2.11. “Interest
Account” shall mean the bookkeeping account established to record the interests
of an Eligible Director with respect to deferred Compensation that is not
allocated to Units in a Stock Unit Account.
2.12. “Shares”
shall mean shares of Stock.
2.13. “Stock”
shall mean the Class A Common Stock of the Company.
2.14. “Stock
Unit Account” shall mean a bookkeeping account established to record the
interests of an Eligible Director who has elected to have deferred Compensation
credited as Units in this Account.
2.15. “Unit”
shall mean a contractual obligation of the Company to deliver a Share based
on
the Fair Market Value of a Share to an Eligible Director or the beneficiary
or
estate of such Eligible Director as provided herein.
1
Exhibit
10.13
Section
3. Administration.
The
Plan shall be administered by the Committee; provided, however, that the Plan
shall be administered such that any Director participating in the Plan shall
continue to be deemed to be a “disinterested person” under Rule 16b-3 of the
Securities and Exchange Commission under the Exchange Act (“Rule 16b-3”), as
such Rule is in effect on the Effective Date of the Plan and as it may be
subsequently amended, for purposes of such Director’s ability to serve on any
committee charged with administering any of the Company’s stock-based incentive
plans for executive officers intended to qualify for the exemptive relief
available under Rule 16b-3.
Section
4. Shares
Authorized for Issuance.
4.1. Maximum
Number of Shares.
The
aggregate number of Shares which may be issued to Eligible Directors under
the
Plan shall not exceed Two Hundred Fifty Thousand (250,000) Shares, subject
to
adjustment as provided in Section 4.2 below. If any Unit is forfeited without
a
distribution of Shares, the Shares otherwise subject to such Unit shall again
be
available hereunder.
4.2. Adjustment
for Corporate Transactions.
If the
outstanding Stock is increased, decreased, changed into or exchanged for a
different number or kind of shares of the Company through reorganization,
recapitalization, reclassification, stock dividend, stock split or reverse
stock
split, an appropriate and proportionate adjustment shall be made in the number
or kind of shares which may be issued in the aggregate under this Plan and
the
number of Units that have been, or may be, issued under this Plan; provided,
however, that no such adjustment need be made if, upon the advice of counsel,
the Committee determines that such adjustment may result in the receipt of
federally taxable income to holders of Stock or other classes of the Company’s
equity securities. The nature and extent of such adjustments shall be determined
by the Committee in its sole discretion, and any such determination as to what
adjustments shall be made, and the extent thereof, shall be final, binding
and
conclusive. No fractional shares of Stock shall be issued under this Plan
pursuant to any such adjustment.
Section
5. Deferred
Compensation Program.
5.1. Election
to Defer.
On or
before December 31 of any calendar year, an Eligible Director may elect to
defer
receipt of all or any part of any Compensation payable in respect of the
calendar year following the year in which such election is made, and to have
such amounts credited, in whole or in part, to a Stock Unit Account or an
Interest Account. Any person who shall become an Eligible Director during any
calendar year may elect, not later than the 30th day after his term as a
Director begins, to defer payment of all or any part of his Compensation payable
for the portion of such calendar year following such election. In the year
in
which this Plan is first implemented, any Eligible Director may elect, not
later
than the 30th day after the Effective Date, to defer payment of all or any
part
of his Compensation payable for the portion of such calendar year following
the
Effective Date.
5.2. Method
of Election.
A
deferral election shall be made by written notice filed with the Corporate
Secretary of the Company. Such election shall continue in effect (including
with
respect to Compensation payable for subsequent calendar years) unless and until
the Eligible Director revokes or modifies such election by written notice filed
with the Corporate Secretary. Any such revocation or modification of a deferral
election shall become effective as of December 31 of the year in which such
notice is given and only with respect to Compensation payable in respect of
the
calendar year following the year in which such revocation or modification is
made; provided however that if the effect of such revocation or modification
of
a deferral election is to change the amount of deferred Compensation that would
otherwise have been credited to the Stock Unit Account, such notice shall in
no
event become effective earlier than six (6) months after it is received by
the
Corporate Secretary. This means that notice must be received by the Corporate
Secretary by July 1 to be effective for the following year. Amounts credited
to
the Eligible Director’s Stock Unit Account prior to the effective date of any
such revocation or modification of a deferral election shall not be affected
by
such revocation or modification and shall be credited and distributed only
in
accordance with the deferral election in place prior to such revocation and
modification and otherwise in accordance with the applicable terms of the Plan.
An Eligible Director who has revoked an election to participate in the Plan
may
file a new election to defer Compensation with respect to services rendered
in
the calendar year following the year in which such new election is filed with
the Corporate Secretary of the Company.
5.3. Investment
Election.
At the
time an Eligible Director elects to defer receipt of Compensation pursuant
to
Section 5.1, the Eligible Director shall also designate in writing the portion
of such Compensation, stated as a whole percentage, to be credited to the
Interest Account and the portion to be credited to the Stock Unit Account.
If an
Eligible Director fails to designate the allocation between the two Accounts,
100% of such Compensation shall be credited to the Interest Account. By written
notice to the Corporate Secretary, an Eligible Director may change the
investment election and the manner in which Compensation is allocated among
the
Accounts but only with respect to services to be rendered in the calendar year
following the year in which such new investment election is filed with the
Corporate Secretary, provided that any such election shall only be effective
with respect to Compensation payable six (6) months after such new investment
election is received by the Corporate Secretary.
5.4. Interest
Account.
a. Any
Compensation allocated to an Eligible Director’s Interest Account shall be
deemed earned and credited to the Interest Account as of the last trading day
of
the fiscal quarter in which the service was provided for which such compensation
amount would have been paid to the Eligible Director.
b. Any
amounts credited to the Interest Account shall be credited with interest at
the
annual rate for the 3-month treasury bill as of the last trading day of the
fiscal quarter as quoted in the Wall Street Journal, times 3/12.
2
Exhibit
10.13
5.5. Stock
Unit Account.
a. Any
Compensation allocated to an Eligible Director’s Stock Unit Account shall be
deemed earned and credited to Units in the Stock Unit Account as of the last
trading day of the fiscal quarter in which the service was provided for which
such compensation amount would have been paid to the Eligible Director.
b. The
number of Units allocated to the Eligible Director’s Stock Unit Account pursuant
to subsection (a) above shall be equal to the quotient of (i) the aggregate
Compensation allocated to the Stock Unit Account as of the last trading day
of
the fiscal quarter divided by (ii) the Fair Market Value on the last trading
day
of such quarter. Fractional Units shall be credited, but shall be rounded to
the
nearest hundredth percentile, with amounts equal to or greater than .005 rounded
up and amounts less than .005 rounded down.
5.6. Dividend
Equivalents.
a. An
Eligible Director who has elected to defer Compensation to a Stock Unit Account
shall have no rights as a stockholder of the Company with respect to any Units
until Shares are distributed and delivered to the Eligible Director.
b. Notwithstanding
the provisions of subsection (a), each Eligible Director who has allocated
Compensation to a Stock Unit Account shall have the right to receive an amount
equal to the dividend per Share declared by the Company on the applicable
dividend payment date (which, in the case of any dividend distributable in
property other than Shares, shall be the per Share value of such dividend,
as
determined by the Company for purposes of income tax reporting) times the number
of Units held by such Eligible Director in his Stock Unit Account (a “Dividend
Equivalent”).
c. Dividend
Equivalents shall be treated as reinvested in an additional number of Units
and
credited to the Eligible Director’s Stock Unit Account.
d. The
additional number of Units to be credited to the Eligible Director’s Stock Unit
Account pursuant to (c) (iii) shall be determined by dividing (i) the product
of
(A) the number of Units in the Eligible Director’s Stock Unit Account on the
date the dividend is declared, and (B) the amount of any cash dividend declared
by the Company on a Share (or, in the case of any dividend distributable in
property other than Shares, the per share value of such dividend, as determined
by the Company for purposes of income tax reporting), by (ii) the Fair Market
Value on the last trading day of the fiscal quarter in which the dividend is
declared.
e. Notwithstanding
the date used for purposes of determining the number of additional Units as
provided in subsection (d) above, the additional Units to be credited for
Dividend Equivalents shall be deemed earned and credited to the Eligible
Director’s Stock Unit Account on the last trading day of the fiscal quarter in
which such dividend is declared.
f. In
the
event of any stock split, stock dividend, recapitalization, reorganization
or
other corporate transaction affecting the capital structure of the Company,
the
Committee shall make such adjustments to the number of Units credited to each
Eligible Director’s Stock Unit Account as the Committee shall deem necessary or
appropriate to prevent the dilution or enlargement of such Eligible Director’s
rights and such adjustment shall be made and effective as of the last day of
the
fiscal quarter in which such corporate transaction has occurred.
5.7. Distribution
Election.
a. At
the
time an Eligible Director makes a deferral election pursuant to Section 5.1,
the
Eligible Director shall also file with the Corporate Secretary a written
election (a “Distribution Election”).
b. The
distribution from the Stock Unit Account shall be made in Shares and the
distribution from the Interest Account shall be made in cash. The Distribution
Election shall specify that such distribution shall commence, at the election
of
the Eligible Director, as soon as practicable following the first business
day
of the calendar month following the date the Eligible Director ceases to be
a
Director or on the first business day following the calendar year in which
the
Eligible Director ceases to be a Director.
c. Such
distribution shall be in one lump sum payment or in such number of annual
installments (not to exceed ten (10)) as the Eligible Director may designate
on
the Distribution Election. The amount of any installment payment shall be
determined by multiplying the amount credited to the Accounts of an Eligible
Director immediately prior to the distribution by a fraction, the numerator
of
which is one and the denominator of which is the number of installments
(including the current installment) remaining to be paid.
d. An
Eligible Director may at any time prior to the time at which the Eligible
Director ceases to be a Director, and from time to time, change any Distribution
Election applicable to his Accounts, provided that no election to change the
timing of any final distribution shall be effective unless (i) it is made in
writing and received by the Corporate Secretary at least one (1) year prior
to
the time at which the Eligible Director ceases to be a director and (ii) the
start date of any installment distribution or lump sum payment is delayed at
least five years.
3
Exhibit
10.13
5.8. Unforeseeable
Emergency Withdrawal
Any
Eligible Director may, after submission of a written request to the Corporate
Secretary and such written evidence of the Eligible Director’s financial
condition as the Committee may reasonably request, withdraw from his Interest
Account (but not from his Stock Unit Account) up to such amount as the Committee
shall determine to be necessary to alleviate the Eligible Director’s
unforeseeable emergency plus applicable taxes as a result of the distribution.
Withdrawals will only be approved for a severe financial hardship to the
Eligible Director resulting from an illness or accident of the Eligible
Director, his or her spouse or dependent (as defined in IRC § 409A (a) (2) (B)
(ii).
5.9. Timing
and Form of Distributions.
a. Any
distribution to be made hereunder, whether in the form of a lump sum payment
or
installments, following the termination of an Eligible Director’s service as a
Director shall commence in accordance with the Distribution Election made by
the
Eligible Director pursuant to Section 5.7.
b. If
an
Eligible Director fails to specify in accordance with Section 5.7 a commencement
date for a distribution or whether such distribution shall be made in a lump
sum
payment or a number of installments, such distribution shall be made in a lump
sum payment and commence on the first business day of the month immediately
following the date on which the Eligible Director ceases to be a Director.
In
the case of any distribution being made in annual installments, each installment
after the first installment shall be paid on the first business day of each
subsequent calendar year, or as soon as practical thereafter, until the entire
amount subject to such Distribution Election shall have been paid.
Section
6. Unfunded
Status.
The
Company shall be under no obligation to establish a fund or reserve in order
to
pay the benefits under the Plan. A Unit represents a contractual obligation
of
the Company to deliver Shares to an Eligible Director as provided herein. The
Company has not segregated or earmarked any Shares or any of the Company’s
assets for the benefit of an Eligible Director or his beneficiary or estate,
and
the Plan does not, and shall not be construed to, require the Company to do
so.
The Eligible Director and his beneficiary or estate shall have only an
unsecured, contractual right against the Company with respect to any Units
granted or amounts credited to an Eligible Director’s Accounts hereunder, and
such right shall not be deemed superior to the right of any other creditor.
Units shall not be deemed to constitute options or rights to purchase
Stock.
Section
7. Amendment
and Termination.
The
Plan may be amended at any time by the Committee or the Board of Directors.
Any
modification of any of the terms and provisions of the Plan, including this
Section, shall not be made more than once every six (6) months. The Plan shall
terminate on May 31, 2008. Unless the Board otherwise specifies at the time
of
such termination, the termination of the Plan will not result in the premature
distribution of the amounts credited to an Eligible Director’s
Accounts.
Section
8. General
Provisions.
8.1. No
Right to Serve as a Director.
This
Plan shall not impose any obligations on the Company to retain any Eligible
Director as a Director nor shall it impose any obligation on the part of any
Eligible Director to remain as a Director of the Company.
8.2. Rights
of a Terminated Director.
Notwithstanding the fact that an Eligible Director ceases to be a director
during any fiscal quarter, the Eligible Director’s Accounts shall be credited,
on the last trading day of the fiscal quarter, with all Compensation and
Dividend Equivalents earned as of the last business day he served as an Eligible
Director.
8.3. Construction
of the Plan.
The
validity, construction, interpretation, administration and effect of the Plan
and the rights relating to the Plan, shall be determined solely in accordance
with the laws of the State of Delaware.
8.4. No
Right to Particular Assets.
Nothing
contained in this Plan and no action taken pursuant to this Plan shall create
or
be construed to create a trust of any kind or any fiduciary relationship between
the Company and any Eligible Director, the executor, administrator or other
personal representative or designated beneficiary of such Eligible Director,
or
any other persons. Any reserves that may be established by the Company in
connection with Units granted under this Plan shall continue to be treated
as
the assets of the Company for federal income tax purposes and remain subject
to
the claims of the Company’s creditors. To the extent that any Eligible Director
or the executor, administrator, or other personal representative of such
Eligible Director, acquires a right to receive any payment from the Company
pursuant to this Plan, such right shall be no greater than the right of an
unsecured general creditor of the Company.
8.5. Severability
of Provisions.
If any
provision of this Plan shall be held invalid or unenforceable, such invalidity
or unenforceability shall not affect any other provisions hereof, and this
Plan
shall be construed and enforced as if such provision had not been
included.
8.6. Incapacity.
Any
benefit payable to or for the benefit of a minor, an incompetent person or
other
person incapable of receipting therefore shall be deemed paid when paid to
such
person’s guardian or to the party providing or reasonably appearing to provide
for the care of such person, and such payment shall fully discharge any
liability or obligation of the Board of Directors, the Company and all other
parties with respect thereto.
8.7. Headings
and Captions.
The
headings and captions herein are provided for reference and convenience only,
shall not be considered part of this Plan, and shall not be employed in the
construction of this Plan.
4
EXECUTION
VERSION
Exhibit
10.17
AMENDED
AND RESTATED PURCHASE AND SALE AGREEMENT
By
and
Between
Berry
Petroleum Company
and
Orion
Energy Partners L.P.
February
23, 2006
Exhibit
10.17
TABLE
OF
CONTENTS
| Page | |||
|
Section
1.
|
Definitions
|
2
|
|
|
Section
2.
|
Transfer
of POC Units; Purchase Price
|
7
|
|
|
2.1
|
Purchase
and Sale
|
7
|
|
|
2.2
|
Deposit
|
7
|
|
|
2.3
|
Purchase
Price
|
7
|
|
|
2.4
|
Closing
|
8
|
|
|
2.5
|
Payment
|
8
|
|
|
2.6
|
Further
Assurances
|
8
|
|
|
Section
3.
|
Representations
and Warranties of the Company
|
9
|
|
|
3.1
|
Making
of Representations and Warranties
|
9
|
|
|
3.2
|
Authority
|
9
|
|
|
3.3
|
Execution,
Delivery; Valid and Binding Agreement
|
9
|
|
|
3.4
|
No
Breach
|
9
|
|
|
3.5
|
Governmental
Authorities; Consents
|
9
|
|
|
3.6
|
Ownership
of POC Units
|
9
|
|
|
3.7
|
Company
Organization; Qualification
|
10
|
|
|
3.8
|
POC
|
10
|
|
|
3.9
|
[Intentionally
Omitted]
|
10
|
|
|
3.10
|
Absence
of Undisclosed Liabilities
|
10
|
|
|
3.11
|
No
Material Adverse Changes
|
10
|
|
|
3.12
|
Title
to Properties
|
11
|
|
|
3.13
|
Tax
Matters
|
11
|
|
|
3.14
|
Contracts
|
12
|
|
|
3.15
|
Litigation
Against the Company
|
13
|
|
|
3.16
|
Employee
Matters
|
13
|
|
|
3.17
|
Insurance
|
13
|
|
|
3.18
|
Compliance
with Laws; Permits
|
13
|
|
|
3.19
|
Brokerage
|
13
|
|
|
3.20
|
PGR
Leases and PGR Wells
|
13
|
|
|
3.21
|
Marketing
|
13
|
|
|
3.22
|
Change
in Property Condition
|
14
|
|
|
3.23
|
Environmental
Protection
|
14
|
|
|
3.24
|
Warranties
and Representations
|
14
|
|
|
Section
4.
|
Title
Matters
|
16
|
|
|
4.1
|
Purchase
Price Adjustments for Defective Interests
|
16
|
|
|
4.2
|
Interest
Additions
|
17
|
|
|
4.3
|
Title
Dispute Resolution
|
17
|
|
|
4.4
|
Termination
|
18
|
|
|
4.5
|
Preferential
Rights
|
18
|
|
|
Section
5.
|
Covenants
of the Company
|
19
|
|
|
5.1
|
Conduct
of Business
|
19
|
|
|
5.2
|
Access
to Information; Confidentiality
|
19
|
-i-
Exhibit
10.17
TABLE
OF CONTENTS
(continued)
| Page | |||
|
5.3
|
Conditions
|
20
|
|
|
5.4
|
Exclusive
Dealings
|
21
|
|
|
5.5
|
Redemption
of PGR LLC Interests
|
21
|
|
|
5.6
|
Deliveries
|
21
|
|
|
Section
6.
|
Representations
and Warranties of Buyer
|
22
|
|
|
6.1
|
Making
of Representations and Warranties
|
22
|
|
|
6.2
|
Organization
of Buyer
|
22
|
|
|
6.3
|
Authority
of Buyer
|
22
|
|
|
6.4
|
Execution,
Delivery; Valid and Binding Agreement
|
22
|
|
|
6.5
|
No
Breach
|
22
|
|
|
6.6
|
Litigation
|
22
|
|
|
6.7
|
Governmental
Authorities; Consents
|
22
|
|
|
6.8
|
Financing
|
23
|
|
|
6.9
|
Brokerage
|
23
|
|
|
6.10
|
Investment
Representations
|
23
|
|
|
Section
7.
|
Covenants
of Buyer
|
24
|
|
|
7.1
|
Confidentiality
|
24
|
|
|
7.2
|
Compliance
|
24
|
|
|
7.3
|
Conditions
|
24
|
|
|
7.4
|
Due
Diligence
|
24
|
|
|
7.5
|
Notification
|
25
|
|
|
7.6
|
Payment
|
25
|
|
|
7.7
|
Deliveries
|
25
|
|
|
Section
8.
|
[Intentionally
Omitted]
|
25
|
|
|
Section
9.
|
Conditions
|
25
|
|
|
9.1
|
Conditions
to the Obligations of Buyer
|
25
|
|
|
9.2
|
Conditions
to Obligations of the Company
|
26
|
|
|
Section
10.
|
Termination
of Agreement; Rights to Proceed
|
27
|
|
|
10.1
|
Termination
|
27
|
|
|
10.2
|
Effect
of Termination
|
27
|
|
|
Section
11.
|
Miscellaneous
|
28
|
|
|
11.1
|
Fees
and Expenses
|
28
|
|
|
11.2
|
Survival
of Representations and Warranties
|
28
|
|
|
11.3
|
Indemnification
by the Company
|
28
|
|
|
11.4
|
Indemnification
by Buyer
|
28
|
|
|
11.5
|
Limitations
on Indemnity
|
28
|
|
|
11.6
|
Governing
Law; Consent to Jurisdiction
|
28
|
|
|
11.7
|
Arbitration
|
29
|
|
|
11.8
|
Notices
|
29
|
-ii-
Exhibit
10.17
TABLE
OF CONTENTS
(continued)
| Page | |||
|
11.9
|
Entire
Agreement
|
31
|
|
|
11.10
|
Severability
|
31
|
|
|
11.11
|
Assignability;
Binding Effect
|
31
|
|
|
11.12
|
Captions
and Gender
|
31
|
|
|
11.13
|
Execution
in Counterparts/Third Party Beneficiaries
|
31
|
|
|
11.14
|
Amendments
|
31
|
|
|
11.15
|
Publicity
and Disclosures
|
32
|
|
|
11.16
|
Disclosure
Schedules
|
32
|
-iii-
Exhibit
10.17
TABLE
OF CONTENTS
(continued)
SCHEDULES
|
Schedule
3.5
|
Consents
and Approvals
|
|
|
Schedule
3.8
|
POC
Consents
|
|
|
Schedule
3.10
|
Liabilities
|
|
|
Schedule
3.11
|
Material
Adverse Changes
|
|
|
Schedule
3.14
|
Contracts
|
EXHIBITS
|
Exhibit
A
|
PGR
Leases & PGR Wells
|
|
|
Exhibit
B
|
Form
of Assignment for Transfer of POC Units
|
|
|
Exhibit
C
|
Form
of Assignment and Bill of Sale for Direct Assignment
|
|
|
Exhibit
D
|
Form
of Opinion of the Company’s Counsel
|
|
|
Exhibit
E
|
Form
of Non-Competition Agreement
|
|
|
Exhibit
F
|
Form
of Escrow Agreement
|
-iv-
Exhibit
10.17
AMENDED
AND RESTATED PURCHASE AND SALE AGREEMENT
THIS
AMENDED AND RESTATED PURCHASE AND SALE AGREEMENT (“Agreement”)
dated
as of February 23, 2006 by and between Berry Petroleum Company, a Delaware
corporation (“Buyer”)
and
Orion Energy Partners L.P., a Delaware limited partnership (the “Company”).
Unless herein otherwise defined, capitalized terms used in this Agreement are
defined in Section 1.
RECITALS
WHEREAS,
Buyer, the Company and the holders of equity securities of the Company entered
into that certain Purchase and Sale Agreement dated as of January 26, 2006
(the
“Original
Agreement”);
WHEREAS,
the Original Agreement contemplated that Buyer and the Company would execute
this Agreement if the Company was able to obtain the requisite consents and
approvals to allow it to transfer and assign the PGR LLC Interests (as defined
below) to a newly formed, wholly owned subsidiary of the Company and to sell
its
interest in such wholly owned subsidiary to Buyer and if the Company elected
to
proceed in such manner;
WHEREAS,
the Company owns 50% of the issued and outstanding limited liability company
interests (the “PGR
LLC Interests”)
of
Piceance Gas Resources, LLC, a Colorado limited liability company (“PGR”).
PGR
owns certain rights and interests in and to the leasehold estates created by
the
oil and gas leases described on Exhibit A
hereto
(the “PGR
Leases”)
and
the oil and gas wells located on the PGR Leases (the “PGR Wells”)
and
other real and personal properties described on Exhibit
A
(collectively, the “PGR
Assets”);
WHEREAS,
the Company has obtained such consents and approvals to transfer and assign
its
PGR LLC Interests to Piceance Operating Company, LLC, a Colorado limited
liability company (“POC)
formed
for the purposes of holding the Company’s PGR LLC Interest and the PGR Assets,
and elects to sell its 100% interest in POC (the “POC
Units”)
to
Buyer under this Agreement;
WHEREAS,
prior to the Closing Date (as defined herein), the Company will transfer and
assign the PGR LLC Interests to POC and cause POC to redeem all of the PGR
LLC
Interests in consideration of the assignment by PGR to POC of a direct interest
in POC’s proportionate share of the PGR Assets as reflected on Exhibit
A
hereto
(the “Direct
Assignment”).
After
the Direct Assignment, the term “PGR Assets” shall refer to POC’s direct
percentage interest in the PGR Assets.
WHEREAS,
the Company desires to sell to Buyer and Buyer desires to acquire from the
Company all of the POC Units.
AGREEMENT
NOW,
THEREFORE, in consideration of the mutual representations, warranties, covenants
and agreements, and upon the terms and subject to the conditions, herein set
forth, the parties hereto agree as follows:
-1-
Exhibit
10.17
|
Section
1.
|
Definitions.
|
In
addition to any terms defined elsewhere in this Agreement, unless otherwise
specifically provided herein, the following terms shall have the following
meanings for all purposes when used in this Agreement, and in any note,
agreement, certificate, report or other document made or delivered in connection
with this Agreement:
(a) “Affiliate”
means,
with respect to any specified Person, any other Person directly or indirectly
controlled by or under common control with such specified Person; provided
that
the Company shall not be considered an Affiliate of any Seller.
(b) “Allocated
Value”
The
term “Allocated Value” shall mean the value allocated to the PGR Leases as set
forth in Exhibit
A.
(c) “BLM”
means
the Federal Bureau of Land Management.
(d) “Defect
Value”
means
the amount by which the Allocated Value of a Defective Interest has been reduced
by a Title Defect. In determining which portion of a PGR Lease is a Defective
Interest, it is the intent of the parties to include, to the extent possible,
only that portion of the PGR Lease materially and adversely affected by the
defect. The Defect Value shall be determined by the parties in good faith taking
into account all relevant factors, including without limitation, the
following:
(1) If
the
Title Defect is a lien or encumbrance on the PGR Lease, the Defect Value shall
be the cost of removing such lien or encumbrance.
(2) If
the
Title Defect is an actual reduction in NRI, the Defect Value shall be the
Allocated Value for the particular PGR Lease, proportionately reduced by the
ratio of the actual NRI to the represented NRI.
(3) If
the
Title Defect does not fall into subsection (1) or (2), then the Defect
Value shall be determined by the parties in good faith, taking into account
all
relevant factors, including without limitation, the following:
(A) The
Allocated Value of the affected PGR Lease;
(B) The
current status of the Defective Interest (i.e.,
proved
developed producing, etc.) and if such interest is producing, the present value
of the future cash flow, net of capital expenditures, expected to be generated
therefrom;
(C) If
the
Title Defect represents only a possibility of title failure, the probability
that such failure will occur; and
(D) The
legal
effect of the Title Defect.
(e) “Defective
Interest”
means
a
PGR Lease affected by a Title Defect that reduces the Allocated Value of the
affected PGR Lease by more than One Hundred Fifty Thousand Dollars
($150,000.00).
-2-
Exhibit
10.17
(f) “Defensible
Title”
The
term “Defensible Title” with respect to the PGR Wells and PGR Leases means such
title to the PGR Wells and PGR Leases, as reflected in the records of the county
or counties where the PGR Assets are located as of the Closing, that, subject
to
and except for Permitted Encumbrances: (i) entitles PGR to receive not less
than the net revenue interest for the formations set forth for each PGR Well
and
PGR Lease on Exhibit
A
(“NRI”);
(ii) obligates PGR to bear costs and expenses relating to the maintenance,
development, operation and the production of hydrocarbons from the formations
from each PGR Well and PGR Lease in an amount not greater than the working
interest set forth in Exhibit
A
(“WI”);
and
(iii) is free and clear of liens, encumbrances and defects.
(g) “Environmental
Assessment”
has
the
meaning set forth in Section 5.2(c).
(h) “GAAP”
means
generally accepted accounting principles in effect in the United States of
America from time to time, applied on a consistent basis which are applicable
as
of the date on which any calculation is to be made under this Agreement or
as of
the date on which any financial statement is to be prepared under this
Agreement.
(i) “General
Partner”
shall
mean Orion Energy Partners, Inc., a Delaware corporation, the general partner
of
the Company.
(j) “JOA”
means
the AAPL form Joint Operating Agreement initialed by the members of PGR on
February 16 and ratified and adopted by the members of PGR as of February 14,
2005.
(k) “Losses”
shall
mean losses, damages, claims and costs (including reasonable attorneys’ fees and
expenses, but excluding consequential, incidental, exemplary and punitive
damages).
(l) “Permitted
Encumbrances”
shall
mean:
(1) lessors’
royalties, overriding royalties, proceeds interests, net profits interests,
production payments, reversionary interests and similar burdens if the net
cumulative effect of such burdens does not operate to reduce the NRIs below
those set forth on Exhibit
A;
(2) statutory
liens for Taxes or assessments not yet due and delinquent or, if delinquent,
that are being contested in good faith in the normal course of
business;
(3) all
rights to consent by, required notices to, filings with, or other actions by
federal, state or local governmental bodies, in connection with the conveyance
of the applicable PGR Leases if the same are customarily sought after such
conveyance;
(4) rights
of
reassignment contained in any PGR Leases providing for reassignment upon the
surrender or expiration of any PGR Leases;
(5) easements,
rights-of-way, servitudes, permits, surface leases and other rights with respect
to surface operations, on, over or in respect of any of the PGR Leases or any
restriction on access thereto that do not materially interfere with the
operation of the affected PGR Wells or PGR Leases;
-3-
Exhibit
10.17
(6) such
Title Defects as Buyer has waived;
(7) the
terms
and conditions of the Contracts to the extent such terms and conditions do
not
cause the NRI to be less than or the WI to be more than as set forth in
Exhibit
A
for the
applicable PGR Wells or PGR Leases;
(8) statutory
materialmens’, mechanics’, operators’ or other similar liens arising in the
ordinary course of business incidental to operation of the PGR Wells or PGR
Leases (i) if such liens and charges have not been filed pursuant to law
and the time for filing such liens and charges has expired, (ii) if filed,
such liens and charges have not yet become due and payable or payment is being
withheld as provided by law, or (iii) if the validity of any such lien is
being contested in good faith by appropriate action;
(9) rights
reserved to or vested in any federal, state or local governmental body,
authority or agency to control or regulate any of the PGR Wells or PGR Leases
in
any manner; and all applicable laws, rules, regulations and orders of general
applicability in the area of the PGR Leases;
(10)
any
required third party consents to assignments of Contracts or property and
similar agreements burdening any of the PGR Leases (excluding those covered
by
the provisions of Section 4.5 which shall be exclusively dealt with pursuant
to
Section 4.5);
(11)
liens
arising under operating agreements, unitization and pooling agreements and
production sales contracts securing amounts (i) not yet delinquent or, (ii)
if
delinquent, being contested in good faith in the ordinary course of
business;
(12)
all
matters of record as of the date of this Agreement unless the matter has
properly been identified as a Title Defect in a Notice of Defective
Interests;
(13)
any
defects, irregularities or deficiencies in title to easements, rights-of-way
or
other agreements that, individually or in the aggregate, do not materially
adversely affect the ownership, operation, value or use of any of the PGR Wells
or PGR Leases;
(14)
carried
interests described in Section 7 of the Membership Interest Purchase Agreement
between the Company and PGR Partners, LLC dated February 16, 2005;
and
(15)
all
other
liens, charges, encumbrances, instruments, obligations, defects and
irregularities affecting the PGR Wells or PGR Leases that do not (or would
not
upon foreclosure or other enforcement) reduce the NRI set forth in Exhibit A
nor
prevent the receipt of proceeds of production therefrom, nor increase the share
of costs above the working interest set forth in Exhibit A
nor are
such, individually or in the aggregate, as materially interfere with or detract
from the ownership, operation, value or use of any of the PGR Wells or PGR
Leases.
-4-
Exhibit
10.17
(m) “Person”
means
any individual, corporation, limited or general partnership, limited liability
company, business trust, or other association or business entity created and/or
recognized by State statute, or governmental entity.
(n) “PGR
LLC Agreement”
means
the Limited Liability Company Agreement of PGR, dated effective as of February
14, 2005, among the members of PGR.
(o) “POC
LLC Agreement”
means
the Operating Agreement of POC, dated December 12, 2005 between POC and the
Company.
(p) “Subsidiary”
means
any entity of which securities or other ownership interests having ordinary
voting power to elect a majority of the board of directors or other persons
performing similar functions are at the time directly or indirectly owned by
the
Company.
(q) “Taxes”
means
all taxes, charges, fees, levies, or other assessments, including, without
limitation, all income, gross income, gross receipts, sales, use ad valorem,
transfer, franchise, profits, license, withholding, payroll, employment, social
security, unemployment, excise, estimated, production, severance (and similar
taxes and assessments based on or measured by the ownership of property or
the
production of hydrocarbons or the receipt of proceeds therefrom), occupation,
property, or other taxes, fees, assessments, or charges of any kind whatsoever,
including, without limitation, all interest and penalties thereon, and additions
to tax or additional amounts imposed by any taxing authority upon the Company,
POC or PGR.
(r) “Tax
Returns”
means
any return, declaration, report, claim for refund or information return or
statement relating to Taxes, including any schedule or attachment thereto,
and
including any amendment thereof.
(s) “Title
Defect”
means
any lien, encumbrance, adverse claim, defect in or objection to real property
title, excluding Permitted Encumbrances, that alone or in combination with
other
defects renders PGR’s title to the particular PGR Wells or PGR Leases less than
Defensible Title. Notwithstanding the foregoing, the following shall not be
considered Title Defects:
(1) defects
based solely on an assertion that PGR’s files lack information, provided that
any missing information material to the evaluation of the PGR Leases can be
obtained by the reasonable efforts of Buyer;
(2) defects
in the early chain of title consisting of the failure to recite marital status
in a document or omissions of successors of heirship or estate proceedings,
unless Buyer provides a reasonable basis for the assertion that such failure
or
omission has resulted in another party’s actual and superior claim of title to
the relevant PGR Lease;
-5-
Exhibit
10.17
(3) defects
arising out of lack of survey, unless a survey is required by applicable
law;
(4) defects
arising out of lack of corporate or other entity authorization unless Buyer
provides a reasonable basis for the assertion that the action was not authorized
and results in another party’s actual and superior claim of title to the
particular PGR Well or PGR Lease;
(5) defects
that are defensible by possession under applicable statutes of limitation for
adverse possession or for prescription;
(6) defects
asserting a change in WI or NRI based on a change in drilling and spacing units,
tract allocation or other changes in pool or unit participation occurring after
the date of this Agreement;
(7) title
requirements customarily considered as advisory or waivable as a matter of
prudent business judgment.
The
following terms have the meanings set forth in the Section opposite such
term:
|
Term
|
Section
|
|
|
Adjusted
Purchase Price
|
2.3(a)
|
|
|
Breach
|
10.2
|
|
|
Buyer
Representatives
|
7.4
|
|
|
Buyer
Indemnified Persons
|
11.3
|
|
|
Closing
|
2.4
|
|
|
Closing
Date
|
2.4
|
|
|
Closing
Statement
|
2.3(b)
|
|
|
Code
|
3.13(g)
|
|
|
Contracts
|
3.14
|
|
|
CPR
Rules
|
11.4
|
|
|
Defect
Notice Date
|
4.1(a)
|
|
|
Defensible
Title
|
1(h)
|
|
|
Deposit
|
2.2
|
|
|
Direct
Assignment
|
Recitals
|
|
|
Interest
Additions
|
4.2
|
|
|
NRI
|
1(h)
|
|
|
Original
Agreement
|
Recitals
|
|
|
Permits
|
3.20(b)
|
|
|
Permitted
Encumbrances
|
1(p)
|
|
|
PGR
|
Recitals
|
|
|
PGR
Assets
|
Recitals
|
|
|
PGR
Financial Statements
|
3.9
|
|
|
PGR
Leases
|
Recitals
|
|
|
PGR
LLC Interests
|
Recitals
|
-6-
Exhibit
10.17
|
Term
|
Section
|
|
|
PGR
Wells
|
Recitals
|
|
|
POC
|
Recitals
|
|
|
POC
Units
|
Recitals
|
|
|
Purchase
Price
|
2.3(a)
|
|
|
Purchase
Price Adjustment
|
2.3(c)
|
|
|
SEC
|
5.2(b)
|
|
|
Seller
Indemnified Persons
|
11.4
|
|
|
Survival
Period
|
11.2
|
|
|
Termination
Date
|
10.1(b)
|
|
|
Title
Defect Adjustment
|
4.1(b)(1)
|
|
|
Title
Threshold Amount
|
4.1(b)
|
|
|
Value
of Interest Addition
|
4.2
|
|
|
WI
|
1(h)
|
|
Section
2.
|
Transfer
of POC Units; Purchase Price.
|
2.1 Purchase
and Sale.
Upon
the terms and subject to the conditions of this Agreement, the Company agrees
to
sell to Buyer and Buyer agrees to purchase from the Company, the POC
Units.
2.2 Deposit.
On the
date of the Original Agreement, Buyer paid to the Company the sum of Seven
Million Five Hundred Thousand Dollars ($7,500,000) as a deposit (the
“Deposit”)
to be
credited to the Adjusted Purchase Price at Closing. The Deposit shall be
refunded to Buyer if, and only if, this Agreement is terminated pursuant to
Section 10.1 so long as such termination is not the result of Buyer’s
Breach. The Deposit shall not be interest bearing.
2.3 Purchase
Price
(a) Purchase
Price.
The
purchase price (the “Purchase
Price”)
to be
paid by Buyer to the Company for the POC Units shall be One Hundred Fifty
Million Dollars ($150,000,000), which as adjusted pursuant to
Section 2.3(c) shall be referred to as the “Adjusted
Purchase Price.”
(b) Closing
Statement.
The
Company will prepare and deliver to Buyer at least two business days prior
to
Closing a closing statement related to the PGR Assets as of the Closing Date
(the “Closing
Statement”).
The
Closing Statement shall reflect the various adjustments to the Purchase Price
provided in Section 2.3(c) based on operational activities with respect to
the
PGR Assets from October 1, 2005 until the Closing Date and any Title Defect
Adjustment or Interest Addition Adjustment. Such Closing Statement shall include
the calculations used in determining the Title Defect Adjustment and the
Interest Addition Adjustment and shall set forth the Adjusted Purchase
Price.
(c) Purchase
Price Adjustment.
The
Purchase Price shall be adjusted as follows:
-7-
Exhibit
10.17
(i) The
Purchase Price shall be increased
for the
Company’s allocable share of costs, expenses and other liabilities with respect
to the PGR Assets incurred and paid by the Company after September 30, 2005
and
prior to the Closing Date and the Company’s allocable share of costs and
expenses with respect to the PGR Assets incurred after September 30, 2005 and
to
be paid by the Company after Closing, including but not limited to, drilling
and
completion costs, land costs, facilities costs, lease operating costs and
geological consulting fees;
(ii) The
Purchase Price shall be increased
by the
cost of the field inventories to be transferred to Buyer at Closing;
(iii)
The
Purchase Price shall be reduced
for the
Company’s allocable share of revenues with respect to the PGR Assets
attributable to production periods subsequent to September 30, 2005 and received
by the Company prior to the Closing Date, less the amount of royalties,
severance and ad valorem taxes attributable to such revenues;
(iv)
The
Purchase Price shall be reduced
for
accrued ad valorem, property, production, severance and similar taxes and
assessments based on or measured by the ownership of property or the production
of hydrocarbons or the receipt of proceeds therefrom with respect to the PGR
Assets to which Buyer is subject or will be liable; and
(v) The
Purchase Price will be reduced
by any
Title Defect Adjustments as calculated pursuant to Section 4.1 and
increased
by any
Interest Addition Adjustment as calculated pursuant to Section 4.2.
2.4 Closing.
Subject
to the satisfaction or waiver of the closing conditions set forth in Sections
9.1 and 9.2, the closing (the “Closing”)
of the
purchase and sale of the POC Units shall take place at the offices of Davis
Graham & Stubbs LLP at 10:00 a.m. Mountain time on March 1, 2006 or
such earlier or later date as the parties agree (the “Closing
Date”).
Except as otherwise expressly provided in this Agreement or in any document
contemplated by this Agreement, all matters at the Closing shall be considered
to take place simultaneously and no delivery of any documents shall be deemed
complete until all transactions and deliveries of documents are
completed.
2.5 Payment.
At the
Closing, Buyer shall deliver the Adjusted Purchase Price minus the amount of
the
Deposit and the amount of the Escrow Account, if any, to the Company. The amount
of the Escrow Account, if any, shall be paid at Closing to the Escrow
Agent.
2.6 Further
Assurances.
At any
time prior to, and from time to time after, the Closing, the parties hereto
shall, at the request of the other and without further consideration, execute
and deliver further instruments or documents as the other parties hereto may
reasonably require to evidence or otherwise facilitate the consummation of
the
transactions contemplated hereby.
-8-
Exhibit
10.17
|
Section
3.
|
Representations
and Warranties of the Company.
|
3.1 Making
of Representations and Warranties.
The
Company hereby makes to Buyer the representations and warranties contained
in
this Section 3. The representations and warranties of the Company are hereby
qualified by reference to the Disclosure Schedules attached hereto. References
to the “knowledge” of the Company shall mean the actual knowledge, after
reasonable inquiry, of James D. Lightner, Thomas W. Dyk,
Daniel G. Blanchard, Douglas R. Harris or Rodney G.
Mellott.
3.2 Authority.
The
Company has the full right, authority and power to enter into this Agreement
and
each agreement, document and instrument to be delivered by the Company, pursuant
to this Agreement and to carry out the transactions contemplated hereby and
thereby.
3.3 Execution,
Delivery; Valid and Binding Agreement.
The
execution, delivery and performance of this Agreement by the Company and the
consummation of the transactions contemplated hereby have been duly and validly
authorized by all requisite partnership action as may be applicable to the
Company, and no other proceedings are necessary to authorize the execution,
delivery and performance of this Agreement. This Agreement has been duly
executed and delivered by the Company and constitutes the valid and binding
obligation of the Company, enforceable in accordance with its terms, except
as
such enforcement may be limited by applicable bankruptcy, insolvency,
reorganization, moratorium or other laws of general application affecting
enforcement of creditors’ rights or by general principles of
equity.
3.4 No
Breach.
The
execution, delivery and performance of this Agreement by the Company and the
consummation by the Company of the transactions contemplated hereby (i) do
not and will not violate any provision of the organizational documents of the
Company, POC or PGR; (ii) do not and will not violate any federal, state or
local laws or regulations applicable to the Company, POC or PGR or any of their
respective properties or assets; (iii) do not and will not result in the
creation of any lien, security interest, charge or encumbrance upon any of
the
PGR Assets or the POC Units, and (iv) do not and will not result in a material
breach of, constitute a material default under, accelerate any material
obligation under or give rise to a right of termination under any indenture
or
loan agreement or any other material agreement or contract to which the Company,
POC or PGR is a party.
3.5 Governmental
Authorities; Consents.
Except
as set forth in Schedule
3.5,
the
Company is not required to submit any notice, report or other filing with any
governmental authority in connection with the execution or delivery of this
Agreement or the consummation of the transactions contemplated hereby. Except
as
set forth in Schedule
3.5,
no
consent, approval or authorization of any governmental or regulatory authority
or any other party or person is required to be obtained by the Company in
connection with its execution, delivery and performance of this Agreement or
the
transactions contemplated hereby. Schedule
3.5
shall
provide the required timing for obtaining or making application or filing with
respect to the scheduled consents, approvals or authorizations.
3.6 Ownership
of POC Units.
The
Company owns all right, title and interest in and to the POC Units free and
clear of any security interests, claims, liens, pledges, options, encumbrances,
charges, agreements, voting trusts, proxies or other arrangements, restrictions
or limitations of any kind (except for security interests that will be released
prior to or at the Closing). The POC Units represent all of the outstanding
interests in the profits, losses and capital of POC.
-9-
Exhibit
10.17
3.7 Company
Organization; Qualification.
The
Company is a limited partnership duly formed, validly existing and in good
standing under the laws of the State of Delaware and has the requisite power
and
authority to own and operate its properties and to carry on its business as
now
conducted. The Company is qualified to do business as a foreign limited
partnership in every jurisdiction in which the nature of its business or its
ownership of property requires it to be so qualified except for those
jurisdictions in which the failure to be so qualified would not, individually
or
in the aggregate, have a material adverse effect on the Company’s business or
financial condition. PGR is a limited liability company duly formed, validly
existing and in good standing under the laws of the State of Colorado and has
the requisite power and authority to own and operate its properties and to
carry
on its business as now conducted.
3.8 POC.
POC is
a limited liability company duly formed, validly existing and in good standing
under the laws of the State of Colorado. POC was formed on December 12, 2005
as
a Colorado limited liability company and as of the date of this Agreement does
not own and has never owned any assets and is not subject to any liabilities.
The Company and POC have satisfied all conditions and obtained all consents
and
approvals necessary to enable (i) the transfer and assignment of the PGR LLC
Interests by the Company to POC, (ii) POC to act as the Operator under the
JOA,
and (iii) the redemption of the PGR LLC Interests by POC in consideration for
the Direct Assignment, other than as provided in Schedule
3.8,
which
shall set forth all such consents and approvals obtained or to be obtained,
and
the transfer of such PGR LLC Interests and the redemption and Direct Assignment
will be effected in compliance with applicable law and the terms of all
applicable agreements.
3.9 [Intentionally
Omitted]
3.10
Absence
of Undisclosed Liabilities.
Except
as set forth on Schedule
3.10,
as of
the Closing Date, there are no liabilities of POC or related to the PGR Assets,
whether contingent, absolute, determined or otherwise, except for accounts
payable incurred in the ordinary course of business.
3.11
No
Material Adverse Changes.
Except
as set forth on Schedule
3.11
or as
otherwise provided in this Agreement or as related to the transfer and
assignment of the PGR LLC Interests to POC and the redemption of the PGR LLC
Interests by POC in connection with the Direct Assignment, since September
30,
2005, the Company and PGR have each operated its business only in the ordinary
course of business consistent with past practice and:
(a) other
than events or circumstances affecting the oil and gas industry or economy
as a
whole, there has been no change in the business of the Company as it relates
to
the PGR Assets, POC or PGR (including any damage or casualty loss to the PGR
Assets not covered by insurance), nor has the Company or PGR entered into a
material transaction or incurred a material expense other than sale expenses,
in
each case other than in the ordinary course of business consistent with past
practice, that would result in a material adverse effect on the PGR Assets,
the
business or financial condition of the Company as it relates to the PGR Assets,
POC or PGR, as applicable;
-10-
Exhibit
10.17
(b) POC
does
not have any employment agreements;
(c) there
have not been sales or transfers by the Company, POC or PGR of properties or
assets which are part of the PGR Assets or cancellation or prepayment of
material debts or claims or waiver of material rights by the Company or PGR
relating to the PGR Assets;
(d) there
has
not been an amendment or termination of a material contract related to the
PGR
Assets or to which PGR or POC is or was a party;
(e) there
has
not been a regulatory decision by a governmental authority regarding any of
PGR
Assets that would have a material adverse effect on the PGR Assets;
and
(f) there
has
not been any incurrence, assumption or guarantee by the Company, POC or PGR
of
any indebtedness.
3.12
Title
to Properties.
(a) As
of the
date of this Agreement, PGR owns the PGR Leases and PGR Wells described on
Exhibit A.
Exhibit A
separately lists the related NRIs and WIs for each such PGR Lease and sets
forth
the Allocated Value of each PGR Lease. PGR has Defensible Title to the PGR
Leases. As of the Closing Date, after the transfer and assignment of the PGR
LLC
Interests to POC and the redemption by POC of the PGR LLC Interests in
connection with the Direct Assignment, POC will own directly the interest
reflected in Exhibit
A
hereto
in each of the PGR Leases and PGR Wells, subject to the provisions of the PGR
LLC Agreement.
(b) The
Company has delivered to Buyer or made available for Buyer’s inspection complete
and accurate copies of each of the PGR Leases, and none of such PGR Leases
has
been modified in any respect, except to the extent that such modifications
are
disclosed by the copies delivered to or made available for inspection by Buyer
and except for Direct Assignment. To the knowledge of the Company, PGR is not
in
default under any of the PGR Leases, and no event has occurred and no
circumstances exist which would, either with or without notice or the passage
of
time or both, result in such default under any of the PGR Leases.
(c) To
the
knowledge of the Company, the equipment and other tangible assets used by PGR
in
the conduct of its oil and gas operations are, in all material respects, in
good
condition and repair, ordinary wear and tear excepted.
3.13
Tax
Matters.
(a) Each
of
the Company, POC and PGR has: (i) timely filed all Tax Returns required to
be filed or sent by it in respect of any Taxes or required to be filed or sent
by it by any taxing authority having jurisdiction; and (ii) timely and properly
paid all Taxes shown to be due and payable on such Tax Returns.
-11-
Exhibit
10.17
(b) There
are
no liens for Taxes upon any assets of the Company, POC or PGR, except liens
for
Taxes not yet due as of the Closing Date, or which are being contested in good
faith by all appropriate proceedings.
(c) No
deficiency for any Taxes has been asserted or assessed against the Company,
POC
or PGR that has not been resolved and paid in full. No waiver, extension or
comparable consent given by the Company, POC or PGR regarding the application
of
the statute of limitations with respect to any Taxes or Tax Returns is
outstanding, nor is any request for any such waiver or consent
pending.
(d) None
of
the Company, POC or PGR has requested any extension of time within which to
file
any Tax Return, which Tax Return has not since been filed.
(e) POC
is a
disregarded entity for federal income tax purposes. PGR has been a partnership
for federal and applicable state income tax purposes since the date of its
formation, and has never been taxable as a corporation or as an association
taxable as a corporation.
(f) Each
of
the Company and PGR have disclosed in their Tax Returns all positions taken
therein that could reasonably be expected to give rise to a substantial
understatement of tax within the meaning of Section 6662 of the Internal Revenue
Code of 1986, as amended (the “Code”) or any corresponding provision of state
tax law, including any required filing of Form 8886 and compliance with
alternative disclosure procedures utilizing Schedule M-3. There are no
outstanding rulings, or requests for rulings, with any income tax authority
addressed to either of the Company or PGR that are, or if issued would be,
binding upon either of the Company or PGR for any tax period ending after the
Closing Date.
(g) Neither
the Company nor PGR has (i) executed, become subject to or entered into any
closing agreement pursuant to Section 7121 of the Code that would be binding
on
either of the Company or PGR, (ii) agreed to any extension of time with respect
to the payment of any Taxes of either of the Company or PGR or any limitation
period regarding the assessment of any such Taxes, or (iii) received approval
to
make or agreed to a change in any accounting method or has any application
pending with any Tax authority requesting permission for any such
change.
3.14 Contracts. (a)
All operating agreements, production sales contracts, farmout agreements and
other contracts or agreements relating to the PGR Leases and PGR Wells can
be
found either of record in the counties in which the PGR Leases are located
or
have been made available to Buyer and are listed on Schedule
3.14(a)
and all
other contracts to which the Company is a party that relate to the PGR Assets
and to which PGR is a party that involve the performance of services or delivery
of goods or materials by or to, or the expenditure or receipts of, the Company,
POC or PGR of an amount or value in excess of $150,000, are listed on
Schedule
3.14(a)
(all of
the foregoing, collectively, the “Contracts”)
and to
the knowledge of the Company, the Contracts are currently in full force and
effect in accordance with their applicable terms. (b) Schedule
3.14(b)
lists
all Contracts that will be assigned by the Company to POC and the required
timing of such assignments.
-12-
Exhibit
10.17
3.15
Litigation
Against the Company.
There
are no actions, suits, proceedings, orders or investigations pending against
the
Company relating to the PGR Assets, POC or PGR or to which the Company (with
respect to action relating to the PGR Assets), POC or PGR are a party.
3.16
Employee
Matters.
POC
currently has no employees.
3.17
Insurance.
The
Company maintains insurance with respect to the PGR Assets and PGR’s operations.
All of such insurance policies are in full force and effect and will be in
full
force and effect through the Closing Date. The Company is not in default with
respect to its obligations under any of such insurance policies.
3.18
Compliance
with Laws; Permits.
(a) The
Company, POC and, to the knowledge of the Company, PGR are not in violation
of
or in default under any law, regulation or order applicable to it, the effect
of
which, individually or in the aggregate with such other violations and defaults,
could reasonably be expected to have a material adverse effect on the PGR Assets
or the business or financial condition of the Company as related to the PGR
Assets, POC or PGR.
(b) To
the
knowledge of the Company, PGR has and on the Closing Date, POC will have, in
full force and effect, or with respect to the Direct Assignment, will have
filed
or applied to obtain, all licenses, permits and certificates, from federal,
state and local authorities used in and, individually or in the aggregate,
material to the business or financial condition of PGR or POC, as applicable
(collectively, the “Permits”).
To
the knowledge of the Company, PGR has conducted its business in compliance
with
all material terms and conditions of the Permits.
3.19
Brokerage.
No
third party shall be entitled to receive any brokerage commissions, finder’s
fees, fees for financial advisory services or similar compensation in connection
with the transactions contemplated by this Agreement based on any arrangement
or
agreement made by or on behalf of the Company.
3.20
PGR
Leases and PGR Wells.
To the
knowledge of the Company, all of the PGR Wells have been or are being drilled,
completed and operated (i) within the boundaries of the PGR Leases or
within the limits otherwise permitted by contract, pooling or unit agreement,
and by law and (ii) are in material compliance with all applicable rules,
regulations, permits, judgments, orders and decrees of any court or the federal
and state regulatory authorities having jurisdiction thereof.
3.21
Marketing.
To the
knowledge of the Company, no amounts of hydrocarbons produced from the PGR
Leases are subject to a sales contract (except for contracts terminable without
penalty by PGR on not more than 30 days notice), and no person has any call
upon, option to purchase or similar rights under any agreement with respect
to
the PGR Leases or to the production therefrom. PGR has not in any respect
collected any proceeds from the sale of hydrocarbons produced from the PGR
Leases that are subject to a material refund. As of the Closing Date, proceeds
from the sale of oil, condensate and gas from the PGR Leases were being received
in all respects by POC in a timely manner and were not being held in suspense
for any reason. PGR has not been nor will POC be obligated by virtue of any
prepayment made under any production sales contract or any other contract
containing a “take or pay” clause, or under any gas balancing, deferred
production or similar arrangement to deliver oil, gas or other minerals produced
from or allocated to any of the PGR Leases at some future time without receiving
full payment therefor at the time of delivery. There are no material gas
imbalances as between PGR or POC and any third party with respect to operations
relating to the PGR Leases.
-13-
Exhibit
10.17
3.22
Change
in Property Condition.
Since
September 30, 2005, there has occurred no physical change in the real property
relating to the PGR Leases (other than operations and productions in the
ordinary course) or other casualty that adversely affects the value, use or
operation of any of such Leases (other than declines due to actual depletion),
except ordinary wear and tear and except any changes as would not have a
material adverse effect.
3.23
Environmental
Protection.
To the
knowledge of Company, the Company, POC and PGR have obtained all permits,
licenses and other authorizations with respect to the PGR Assets which are
required under federal, state and local laws relating to pollution or protection
of the environment, including laws relating to emissions, discharges, releases
or threatened releases of pollutants, contaminants, or hazardous or toxic
materials or wastes into ambient air, surface water, ground water, or land,
or
otherwise relating to the manufacture, processing, distribution, use, treatment,
storage, disposal, transport, or handling of pollutants, contaminants or
hazardous or toxic materials or wastes and true copies of all such permits,
licenses and authorizations have been delivered to or made available for
inspection by Buyer. To the knowledge of Company, the Company, POC and PGR
are
in compliance with all terms and conditions of the required permits, licenses
and authorizations, and are also in compliance with all other limitations,
restrictions, conditions, standards, prohibitions, requirements, obligations,
schedules and timetables applicable to the PGR Assets contained in those laws
or
contained in any regulation, code, plan, order, decree, judgment, notice or
demand letter issued, entered, promulgated or approved thereunder. None of
the
Company, POC or, to the knowledge of the Company, PGR has received notice of
any
past, present or future events, conditions, circumstances, activities,
practices, incidents, actions or plans with respect to the PGR Assets which
have
not been remedied and which may interfere with or prevent continued compliance,
or which may give rise to any common law or legal liability, or otherwise form
the basis of any claim, action, suit, proceeding, hearing or investigation,
based on or related to the manufacture, processing, distribution, use,
treatment, or threatened release into the environment, of any pollutant,
contaminant, or hazardous or toxic material or waste.
3.24
Warranties
and Representations.
THE PGR
ASSETS HAVE BEEN UTILIZED BY THE COMPANY AND PGR FOR THE PURPOSE OF EXPLORATION,
DEVELOPMENT, AND/OR PRODUCTION OF OIL AND GAS. THE COMPANY HAS MADE AVAILABLE
TO
BUYER PHYSICAL ACCESS TO THE PGR ASSETS AND, TO THE COMPANY’S KNOWLEDGE, ALL
AVAILABLE INFORMATION REGARDING CRUDE OIL, GAS AND PRODUCED WATER WHICH MAY
HAVE
BEEN SPILLED OR DISPOSED OF ONSITE AND THE LOCATIONS THEREOF; PIT CLOSURES,
BURIAL, LANDFARMING, LANDSPREADING, AND UNDERGROUND INJECTION; AND SOLID WASTE
DISPOSAL SITES, IF ANY EXIST, HAVE BEEN MADE AVAILABLE TO BUYER. BUYER
ACKNOWLEDGES THAT THERE MAY HAVE BEEN SPILLS OF THESE OR OTHER MATERIALS IN
THE
PAST ONTO THE PGR ASSETS. IN ADDITION, SOME PRODUCTION EQUIPMENT MAY CONTAIN
ASBESTOS AND/OR NATURALLY OCCURRING RADIOACTIVE MATERIAL (HEREINAFTER REFERRED
TO AS “NORM”). IN THIS REGARD, BUYER EXPRESSLY UNDERSTANDS THAT NORM MAY AFFIX
OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS AND EQUIPMENT AS SCALE,
OR IN
OTHER FORMS, AND THAT WELLS, MATERIALS AND EQUIPMENT LOCATED ON THE LANDS MAY
CONTAIN NORM AND THE NORM-CONTAINING MATERIAL MAY BE BURIED AND OTHERWISE
DISPOSED OF ON THE PGR ASSETS. BUYER ALSO EXPRESSLY UNDERSTANDS THAT SPECIAL
PROCEDURES MAY BE REQUIRED FOR THE REMOVAL AND DISPOSAL OF ASBESTOS AND NORM
FROM THE EQUIPMENT AND PGR ASSETS WHERE IT MAY BE FOUND AND THAT BUYER ASSUMES
ALL LIABILITY FOR ASSESSMENT, REMOVAL AND DISPOSAL OF ANY SUCH MATERIALS AND
ASSOCIATED ACTIVITIES.
-14-
Exhibit
10.17
EXCEPT
AS
ELSEWHERE PROVIDED IN THIS AGREEMENT, THIS AGREEMENT IS EXECUTED WITHOUT
WARRANTY OF TITLE, EITHER EXPRESS OR IMPLIED, WITHOUT ANY EXPRESS OR IMPLIED
WARRANTY OR REPRESENTATION AS TO THE MERCHANTABILITY OF ANY OF THE EQUIPMENT
OR
PERSONAL PROPERTY OR ITS FITNESS FOR ANY PURPOSE AND WITHOUT ANY OTHER EXPRESS
OR IMPLIED WARRANTY OR REPRESENTATION WHATSOEVER. BUYER UNDERSTANDS AND AGREES
THAT THIS AGREEMENT IS MADE ON AN “AS IS, WHERE IS” BASIS AND BUYER RELEASES THE
COMPANY FROM ANY LIABILITY WITH RESPECT THERETO WHETHER OR NOT CAUSED BY OR
ATTRIBUTABLE TO COMPANY’S NEGLIGENCE EXCEPT AS OTHERWISE PROVIDED HEREIN.
WITHOUT LIMITING THE ABOVE, AND EXCEPT AS EXPRESSLY PROVIDED HEREIN, BUYER
WAIVES ITS RIGHT TO RECOVER FROM THE COMPANY AND FOREVER RELEASES, DISCHARGES
AND INDEMNIFIES THE COMPANY FROM ANY AND ALL DAMAGES, CLAIMS, LOSSES,
LIABILITIES, PENALTIES, FINES, LIENS, JUDGMENTS, COSTS OR EXPENSES WHATSOEVER,
(INCLUDING, WITHOUT LIMITATION, ATTORNEYS’ FEES AND COSTS), WHETHER DIRECT OR
INDIRECT, KNOWN OR UNKNOWN, FORESEEN OR UNFORESEEN, THAT MAY ARISE ON ACCOUNT
OF
OR IN ANY WAY BE CONNECTED WITH THE PHYSICAL CONDITION OF THE PGR ASSETS OR
ANY
FEDERAL, STATE OR LOCAL LAW OR REGULATION APPLICABLE THERETO, INCLUDING, WITHOUT
LIMITATION, THE COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION, AND
LIABILITY ACT OF 1980, AS AMENDED (42 U.S.C. §9601 ET.
SEQ.),
THE
RESOURCE CONSERVATION AND RECOVER ACT OF 1976 (42 U.S.C. §6901 ET.
SEQ.),
THE
CLEAN WATER ACT (33 U.S.C. §466 ET.
SEQ.),
THE
SAFE DRINKING WATER ACT (14 U.S.C. §1401-1450), THE HAZARDOUS MATERIALS
TRANSPORTATION ACT (49 U.S.C. §1801 ET.
SEQ.),
AND
THE TOXIC SUBSTANCE CONTROL ACT (15 U.S.C. §2601-2629).
THE
COMPANY MAKES NO WARRANTY OR REPRESENTATION, EXPRESS, IMPLIED, STATUTORY OR
OTHERWISE, AS TO THE ACCURACY OR COMPLETENESS OF ANY DATA, RESERVE OR OTHER
REPORTS, RECORDS, PROJECTIONS, INFORMATION OR MATERIALS NOW, HERETOFORE OR
HEREAFTER FURNISHED OR MADE AVAILABLE TO BUYER IN CONNECTION WITH THIS
AGREEMENT, INCLUDING, WITHOUT LIMITATION, ANY DESCRIPTION OF THE PGR ASSETS,
PRICING ASSUMPTIONS, OR QUALITY OR QUANTITY OF HYDROCARBON RESERVES (IF ANY)
ATTRIBUTABLE TO THE PGR ASSETS OR THE ABILITY OR POTENTIAL ABILITY OF THE PGR
ASSETS TO PRODUCE HYDROCARBONS OR THE ENVIRONMENTAL CONDITION OF THE PGR ASSETS
OR ANY OTHER MATTERS CONTAINED IN CONFIDENTIAL INFORMATION OR ANY OTHER
MATERIALS FURNISHED OR MADE AVAILABLE TO BUYER BY COMPANY OR ITS AGENTS OR
REPRESENTATIVES; ANY AND ALL SUCH DATA, RECORDS, REPORTS, PROJECTIONS,
INFORMATION AND OTHER MATERIALS FURNISHED BY THE COMPANY OR BY COMPANY’S AGENTS
OR REPRESENTATIVES OR MADE AVAILABLE TO BUYER ARE PROVIDED TO BUYER AS A
CONVENIENCE, AND SHALL NOT CREATE OR GIVE RISE TO ANY LIABILITY OF OR AGAINST
COMPANY; AND
ANY RELIANCE ON OR USE OF THE SAME SHALL BE AT BUYER’S SOLE
RISK.
-15-
Exhibit
10.17
|
Section
4.
|
Title
Matters.
|
4.1 Purchase
Price Adjustments for Defective Interests.
(a) Notice
of Defective Interest.
Buyer
shall give the Company written “Notice of Defective Interests” as soon as
possible but no later than five (5) business days before the Closing Date,
(the
“Defect
Notice Date”).
This
notice must be in writing and satisfy the following conditions precedent: (i)
a
description of each Defective Interest; (ii) the basis for each Defective
Interest, and, if the basis is derived from any document, a copy of such
document (or pertinent part thereof) shall be attached or if the basis is
derived from any gap in PGR’S chain of title, the documents preceding and
following the gap shall be attached; (iii) the Allocated Value of the affected
PGR Lease; and (iv) Buyer’s good faith estimate of the Defect Value and the
computations upon which Buyer’s estimate is based. If a PGR Lease has not been
given an Allocated Value or the Allocated Value of PGR Lease is Fifty Thousand
Dollars ($50,000) or less, the Company shall be deemed to have Defensible Title
to such PGR Lease.
(b) Defect
Adjustments.
(1) If
a PGR
Lease is a Defective Interest, the Purchase Price will be reduced under Section
2.3(c)(ii) by the corresponding Defect Value (which reduction is called a
“Title
Defect Adjustment”)
unless
prior to the Closing Date:
(A) the
Company either cures the Title Defect to Buyer’s reasonable satisfaction or
elects to cure the Title Defect no later than 90 days after Closing;
or
(B) Buyer
elects to waive the relevant Title Defect.
The
Purchase Price shall be adjusted pursuant to Section 2.3 for Defective Interests
only if the aggregate of all Defect Values, net of the Value of all Interest
Additions, for all of the PGR Leases exceeds 3% of the Purchase Price (the
“Title
Threshold Amount”).
(2) If
a PGR
Lease is a Defective Interest for which an adjustment to the Purchase Price
would otherwise be required and the Company elects to cure the defect after
Closing, Buyer and the Company shall at Closing in good faith agree to place
a
portion of the Purchase Price into an escrow account (the “Escrow
Account”)
established pursuant to an escrow agreement in substantially the form attached
hereto as Exhibit F
(the
“Escrow
Agreement”)
with
Wells Fargo Bank or another mutually acceptable financial institution
(“Escrow
Agent”)
until
Buyer’s receipt of the Company’s curative materials. The amount of the Escrow
Account shall be the aggregate of all Defect Values net of the Value of Interest
Additions.
-16-
Exhibit
10.17
(3) If
the
Company has elected to cure a Title Defect and such Title Defect is cured on
or
before 90 days after Closing, the Escrow Agent shall distribute to the Company,
immediately upon Buyer’s receipt of curative materials reasonably satisfactory
to Buyer, the amount placed in the Escrow Account with respect to such Title
Defect (and any account interest accrued thereon).
(4) If
the
Company does not cure a Title Defect within the 90 day time period, Buyer shall
be entitled to an amount equal to the corresponding Defect Value as provided
in
Section 4.1(b)(1).
(5) If
Buyer
disputes the adequacy of the Company’s curative material, Buyer must invoke the
dispute resolution mechanism set forth in Section 4.3 within 30 days after
receipt thereof. If the parties dispute the Defect Value of a Defective Interest
which is not timely cured, then the provisions of Section 4.3 shall
apply.
4.2 Interest
Additions.
Promptly on discovery, Buyer or the Company, whichever is the discovering party
shall notify the other of any interest that entitles PGR to receive more than
the NRI set forth in Exhibit
A,
or
obligates PGR to bear costs and expenses in an amount less than the WI set
forth
in Exhibit
A
(collectively, “Interest
Additions”).
The
party who discovers Interest Additions must give the other party written notice
of Interest Additions as soon as possible, but in no event later than on or
before two (2) business days prior to Closing. This notice must be in writing
and must include (i) a description of each Interest Addition, (ii) the
basis for each Interest Addition, (iii) the Allocated Value of the PGR
Lease affected by the Interest Addition, and (iv) the value of the Interest
Addition or the amount by which the notifying party believes the Allocated
Value
of the PGR Lease has been increased by the Interest Addition (“Value
of Interest Addition”)
and
the computations upon which such party’s belief is based. The Value of Interest
Addition shall be determined by the parties in good faith taking into account
all relevant factors and the Purchase Price will be increased in accordance
with
Section 2.3 by such an amount (“Interest
Addition Adjustment”)
if the
aggregate of all Interest Addition Adjustments, net of the aggregate of all
Defect Values, exceeds One Hundred Fifty Thousand Dollars ($150,000.00) (the
“Addition
Threshold Amount”).
4.3 Title
Dispute Resolution.
The
parties agree to resolve disputes concerning the following matters pursuant
to
this Section: (i) the existence and scope of a Title Defect, (ii) the
Defect Value of that portion of the PGR Lease affected by a Title Defect,
(iii) the Value of an Interest Addition, and (iv) the adequacy of the
Company’s Title Defect curative materials (the “Title
Disputed Matters”).
The
parties agree to attempt to initially resolve all disputes through good faith
negotiations. If the parties cannot resolve disputes regarding items (i), (ii)
or (iii) on or before fifteen (15) days after Closing, the Disputed Matters
will
be finally determined by binding arbitration pursuant to Section 11.7 with
an
independent arbitrator mutually acceptable to the parties or, if none, with
a
panel of three arbitrators appointed pursuant to Section 11.7 who are qualified
by education, knowledge and experience with title defects affecting the types
of
properties which are subject to the disputed Title Defect and have a minimum
of
ten years experience with such types of defects and properties. The
arbitrator(s) shall take into account the factors set forth in the definition
of
“Defect Value” and employ such independent attorneys, petroleum engineers and/or
other consultants as deemed necessary. On or before 60 days after Closing,
Buyer
and the Company shall present their respective positions in writing to the
Arbitrator(s), together with such evidence as each party deems appropriate.
The
Arbitrator(s) shall be instructed to resolve the dispute through a final
decision within 90 days after Closing and the final decision may be reflected
in
a final settlement statement. If the parties cannot resolve disputes regarding
Section 4.3 (iv) within five (5) days after Buyer’s receipt of the Company’s
Title Defect curative materials, the dispute will similarly be finally
determined by binding arbitration pursuant to Section 11.7 and this Section
4.3
but the arbitration hearing shall be held no later than fifteen (15) days after
Buyer’s receipt of the Company’s Title Defect curative materials with a final
decision no later than twenty-five (25) days after Buyer’s receipt of the
Company’s Title Defect curative materials and the final decision shall similarly
be reflected in a final settlement statement.
-17-
Exhibit
10.17
4.4 Termination.
Notwithstanding the foregoing, if the aggregate of all Defect Values, net of
the
Value of all Interest Additions, for all of the PGR Leases exceeds Ten Percent
(10%) of the Purchase Price set forth in Section 2.3, the Company or Buyer
may
terminate this Agreement upon written notice to the other party delivered no
later than 5:00 p.m. on the day before the scheduled Closing Date; provided
however that Buyer, at its sole discretion, may elect to waive all or any
portion of any Title Defect to reduce the aggregate Title Defect Values below
such percentage in which event this Agreement shall remain in full force and
effect. If a party has elected to exercise this right of termination and the
other party does not agree that the right of termination has been triggered,
the
objecting party shall notify the other party on or before 5:00 p.m. on the
scheduled Closing Date and, thereafter, unless the parties are able to resolve
the dispute within three (3) days after the originally scheduled Closing Date,
the matter shall be determined by binding arbitration pursuant to Section 11.7,
before a panel of arbitrators meeting the qualifications set forth in Section
4.3, and with the arbitrators to be appointed and the arbitration to be
conducted within the time frame provided in Section 4.3 for Title Disputed
Matters other than those relating to Title Defect curative materials. In the
event of an objection over whether the right to terminate has been triggered,
the Closing shall be extended until three (3) business days after the dispute
is
resolved by parties as provided in this Section 4.4 or the parties receive
a
final decision from the arbitrators, whichever is applicable.
4.5 Preferential
Rights.
The
Company has no knowledge of any preferential rights of third parties applicable
to the transaction contemplated by this Agreement. Nonetheless, if prior to
Closing, the Company or Buyer becomes aware of any claims asserted by third
parties that preferential rights are applicable to this transaction, it shall
promptly notify the other party of such fact. In such event, the Company agrees
(a) to join in the defense of such claim, (b) to present the best defense
possible, (c) to deliver to Buyer copies of such records, documents, files
and
other data which it possesses pertaining to such claim, and (d) to take such
actions or do, or cause to be done, all things necessary, proper or advisable,
which Buyer may reasonably and lawfully request in defense against such claims.
The Company shall bear its own costs incurred in performing its obligations
under this section.
-18-
Exhibit
10.17
|
Section
5.
|
Covenants
of the Company.
|
5.1 Conduct
of Business.
Unless
otherwise contemplated by this Agreement or related to the transfer and
assignment of the PGR LLC Interest to POC and the redemption by POC of the
PGR
LLC Interest in connection with the Direct Assignment, or unless otherwise
approved by Buyer in writing, from the date hereof until the Closing Date,
the
Company shall:
(a) conduct
its business with respect to the PGR Assets and the business of PGR only in
the
ordinary course and refrain from changing or introducing any method of
management or operations except in the ordinary course of business and
consistent with prior practices;
(b) refrain
from doing or permitting to occur any of the following: (i) selling, pledging,
disposing of or encumbering any of the PGR Assets except (A) pursuant to
existing contracts or commitments or (B) in the ordinary course of business;
(ii) amending the PGR LLC Agreement, (iii) allowing PGR to incur any
indebtedness for borrowed money except accounts payable and other expenditures
in the ordinary course of business or issue any debt securities;
(c) (i)
use commercially reasonable efforts to preserve intact the Company’s business
organization and goodwill with respect to the PGR Assets and PGR’s business
organization and goodwill and maintain its business relationships with
suppliers, distributors, customers and others having business relationships
with
the Company and PGR consistently with past practice; (ii) confer with
representatives of Buyer to report operational matters and the general status
of
ongoing operations; (iii) promptly notify Buyer in writing if the Company
shall discover that any representation or warranty made in this Agreement was
when made, or has subsequently become, untrue in any respect; and
(d) (i)
file any Tax Returns, elections or information statements with respect to
any liabilities for Taxes of the Company, POC or PGR or other matters relating
to Taxes of the Company, POC or PGR which pursuant to applicable law must be
filed prior to the Closing Date; (ii) promptly upon filing provide copies
of any such Tax Returns, elections or information statements to Buyer; and
(iii) make any new Tax elections or other discretionary positions or change
any existing Tax elections or other discretionary positions with respect to
Taxes affecting POC, the PGR Assets or PGR only upon prior consultation with
Buyer.
5.2 Access
to Information; Confidentiality.
(a) From
the
date hereof until the Closing Date, the Company will (i) give Buyer, its
counsel, financial advisors, auditors and other authorized representatives
reasonable access to the offices, properties, books and records of the Company
that relate to the PGR Assets and PGR, (ii) furnish to Buyer, its counsel,
financial advisors, auditors and other authorized representatives such financial
and operating data and other information relating to the PGR Assets and PGR
as
such may be reasonably requested and (iii) instruct the counsel, financial
advisors and other authorized representatives of the Company to cooperate with
Buyer in its investigation of the PGR Assets and PGR. Any investigation pursuant
to this Section shall be conducted in such manner as not to interfere
unreasonably with the conduct of the business of the Company or PGR.
Notwithstanding the foregoing, Buyer shall not have access to other information
which in the Company’s good faith opinion is sensitive or the disclosure of
which could subject the Company to risk of liability.
-19-
Exhibit
10.17
(b) On
and
after the date hereof and through the Closing Date, the Company will afford
promptly to Buyer and its agents reasonable access to its books of account,
financial statements and other records (including, without limitation,
accountant’s work papers), information, knowledgeable personnel and auditors to
the extent necessary or useful for Buyer in connection with the preparation
and
audit of segmented and other financial statements and other reports as may
be
required to be filed by Buyer with the United States Securities and Exchange
Commission (the “SEC”),
any
audit, investigation, dispute or litigation or any other reasonable business
purpose relating to the Company and PGR; provided that any such access by Buyer
shall not unreasonably interfere with the conduct of the business of the Company
or PGR. Buyer shall bear all of the costs and expenses (including, without
limitation, attorneys’ fees) in connection with the foregoing.
(c) The
Company hereby consents to Buyer conducting, prior to Closing and upon advance
notice to the Company, at Buyer’s sole risk and expense, on-site inspections and
an ASTM Phase One Environmental Assessment (an “Environmental
Assessment”)
of the
PGR Wells and PGR Leases; provided that Buyer shall not conduct any sampling
activities without prior notice and consent of the Company, which consent shall
not be unreasonably withheld. In connection with any such on-site inspections
or
Environmental Assessment, Buyer agrees not to interfere with the normal
operation of the PGR Leases and agrees to comply with all requirements and
safety policies of the operator. If Buyer or its agents prepares an
Environmental Assessment of any property, Buyer will furnish copies thereof
to
the Company. The parties shall execute a “common undertaking” letter regarding
the confidentiality of environmental assessments where appropriate. In
connection with the granting of such access, Buyer represents that it is
adequately insured and, waives, releases and agrees to indemnify the Company
and
its representatives against all claims for injury to, or death of, persons
or
for damage to property arising in any way from the access afforded to Buyer
hereunder or the activities of Buyer. This waiver, release and indemnity by
Buyer shall survive termination of this Agreement.
(d) Through
the 90th
day
following the Closing Date, the Company will provide Buyer, its auditors and
other Representatives reasonable access to knowledgeable personnel and the
Company’s auditors to the extent necessary or useful for Buyer in connection
with the preparation and audit of segmented and other financial statements
and
other reports as may be required to be filed by Buyer with the SEC, any audit,
investigation, dispute or litigation or any other reasonable business purpose
relating to the Company and PGR. Buyer shall bear all of the costs and expenses
(including, without limitation, attorneys’ fees) in connection with the
foregoing.
5.3 Conditions.
The
Company shall take all commercially reasonable actions necessary to cause the
conditions set forth in Section 9.1 to be satisfied and to consummate the
transactions contemplated herein as soon as reasonably possible after the
satisfaction thereof.
5.4 Exclusive
Dealings.
The
Company will not directly or indirectly, through any representative or
otherwise, solicit or entertain offers from, negotiate with or in any manner
encourage, discuss, accept, consider or pursue, any proposal of any other person
relating to the acquisition of POC, the PGR Assets or PGR, in whole or in part
(other than with respect to the Excluded Assets), whether directly or
indirectly, through purchase, merger, consolidation or otherwise. The Company
will promptly notify Buyer regarding any contact of which it has knowledge
between the Company or PGR and any other Person regarding any such offer or
proposal or any other related inquiry, including full and complete disclosure
of
all details regarding such contact.
-20-
Exhibit
10.17
5.5 Redemption
of PGR LLC Interests.
The
Company shall transfer and assign its PGR LLC Interests to POC and shall cause
POC to redeem all of the PGR LLC Interests in connection with the Direct
Assignment in accordance with and subject to the provisions of the PGR LLC
Agreement. After the Direct Assignment, the term “PGR Assets” shall refer to
POC’s direct percentage interest in the PGR Assets.
5.6 Deliveries.
On the
Closing Date, the Company shall execute and deliver to Buyer all of the
following:
(a) a
certificate signed by the General Partner of the Company dated as of the Closing
Date to the effect that the statements set forth in paragraphs (a) and (b)
of
Section 9.1 are true and correct;
(b) an
assignment for transfer of the POC Units in form and substance substantially
as
set forth in Exhibit B;
(c) an
assignment and bill of sale for the Direct Assignment in form and substance
substantially as set forth in Exhibit
C;
(d) all
books, records, files and materials of the Company related to the Company’s
administration of the PGR Assets, PGR or POC;
(e) the
Escrow Agreement, if required;
(f) resignation
of any officers of POC;
(g) an
opinion of counsel for the Company in substantially the form set forth in
Exhibit D;
(h) a
nonforeign certificate under Section 1445 of the Code;
(i) a
certificate of good standing with respect to the Company, issued not more than
ten (10) days prior to the Closing Date by (i) the Secretary of State of
the State of Delaware and (ii) by the Secretary of State of Colorado and a
certificate of good standing with respect to POC issued not more than ten (10)
days prior to the Closing Date by the Secretary of State of Colorado;
and
(j) Non-Competition
Agreements in the form attached hereto as Exhibit
E
from
each of the Company, Orion Energy Partners, Inc., James D. Lightner,
Thomas W. Dyk, Daniel G. Blanchard, Douglas R. Harris and
Rodney G. Mellott.
-21-
Exhibit
10.17
|
Section
6.
|
Representations
and Warranties of Buyer.
|
6.1 Making
of Representations and Warranties.
As a
material inducement to the Company to enter into this Agreement and consummate
the transactions contemplated hereby, Buyer hereby makes the representations
and
warranties to the Company contained in this Section 6 as of the date hereof
and
the Closing Date.
6.2 Organization
of Buyer.
Buyer
is a corporation duly organized, validly existing and in good standing under
the
laws of the State of Delaware with full corporate power to own or lease its
properties and to conduct its business in the manner and in the places where
such properties are owned or leased or such business is conducted by
it.
6.3 Authority
of Buyer.
Buyer
has full right, authority and power to enter into this Agreement and each
agreement, document and instrument to be executed and delivered by Buyer
pursuant to this Agreement and to carry out the transactions contemplated hereby
and thereby.
6.4 Execution,
Delivery; Valid and Binding Agreement.
The
execution, delivery and performance of this Agreement by Buyer and the
consummation of the transactions contemplated hereby have been duly and validly
authorized by all requisite corporate action of Buyer and no other proceedings
are necessary to authorize the execution, delivery and performance of this
Agreement. This Agreement has been duly executed and delivered by Buyer and
constitutes the valid and binding obligation of Buyer, enforceable in accordance
with its terms, except as such enforcement may be limited by applicable
bankruptcy, insolvency, reorganization, moratorium or other laws of general
application affecting enforcement of creditors’ rights or by general principles
of equity.
6.5 No
Breach.
The
execution, delivery and performance of this Agreement by Buyer and the
consummation by Buyer of the transactions contemplated hereby (i) do not
and will not violate any provisions of the organizational documents of Buyer;
(ii) do not and will not violate any federal, state, local or foreign laws
or regulations applicable to Buyer; and (iii) do not and will not result in
a material breach of, constitute a material default under, accelerate any
material obligation under or give rise to a right of termination under any
indenture or loan agreement or any other material agreement or contract to
which
Buyer is party.
6.6 Litigation.
There
is no litigation pending or, to Buyer’s knowledge, threatened against Buyer
which would prevent or hinder the consummation of the transactions contemplated
by this Agreement.
6.7 Governmental
Authorities; Consents.
Other
than reports required to be made by Buyer with the SEC, Buyer is not required
to
submit any notice, report or other filing with any governmental authority in
connection with the execution or delivery by it of this Agreement or the
consummation of the transactions contemplated hereby. No consent, approval
or
authorization of any governmental or regulatory authority or any other party
or
Person is required to be obtained by Buyer in connection with its execution,
delivery and performance of this Agreement or the transactions contemplated
hereby.
-22-
Exhibit
10.17
6.8 Financing.
Buyer
has, or will have prior to the Closing, sufficient cash, available lines of
credit or other sources of immediately available funds to enable it to make
payment of the Purchase Price and any other amounts to be paid by it
hereunder.
6.9 Brokerage.
No
third party shall be entitled to receive any brokerage commissions, finder’s
fees, fees for financial advisory services or similar compensation in connection
with the transactions contemplated by this Agreement based on any arrangement
or
agreement made by or on behalf of Buyer.
6.10
Investment
Representations.
(a) Buyer
is
an informed and sophisticated purchaser, and has engaged expert advisors,
experienced in the evaluation and purchase of companies such as the company
as
contemplated hereunder. Buyer has undertaken such investigation and has been
provided with and has evaluated such documents and information as it has deemed
necessary to enable it to make an informed and intelligent decision with respect
to the execution, delivery and performance of this Agreement. Buyer acknowledges
that the Company has given Buyer complete and open access to the key employees,
documents and facilities of the Company and PGR and which are related to the
PGR
Leases. Buyer will undertake prior to Closing such further investigation and
request such additional documents and information as it deems necessary. Buyer
agrees to accept the POC Units and the PGR Assets in the condition they are
in
on the Closing Date based upon its own inspection, examination and determination
with respect thereto as to all matters and without reliance upon any express
or
implied representations or warranties of any nature made by or on behalf of
or
imputed to the Company, except as expressly set forth in this Agreement. Without
limiting the generality of the foregoing, Buyer acknowledges that the Company
makes no representation or warranty with respect to (i) any projections,
estimates or budgets delivered to or made available to Buyer of future revenues,
future results of operations (or any component thereof), future cash flows
or
future financial condition (or any component thereof) of the Company or the
PGR
Assets or the future business and operations of the Company or the PGR Assets
or
(ii) any other information or documents made available to Buyer or its counsel,
accountants or advisors with respect to the PGR Assets or the Company or their
respective businesses or operations, except as expressly set forth in this
Agreement.
(b) Buyer
has
such knowledge and expertise in financial, business and oil and gas matters
that
Buyer is capable of evaluating the merits and risks involved in the purchase
of
the POC Units and the PGR Assets.
(c) Buyer
is
acquiring the POC Units for investment purposes only, solely for the account
of
Buyer (and not as a nominee or agent), and not with a view towards the resale
or
distribution of any part thereof, and Buyer has no present intention of selling,
granting any participation in, or otherwise distributing the same.
(d) Buyer
is
an “accredited investor,” as such term is defined in Rule 501(a) of the
Securities Act.
-23-
Exhibit
10.17
|
Section
7.
|
Covenants
of Buyer.
|
7.1 Confidentiality.
Buyer
agrees that, unless and until the Closing has been consummated, Buyer and the
Buyer Representatives will hold in strict confidence, and will not use, any
confidential or proprietary data or information obtained from the Company with
respect to the business or financial condition of the Company, PGR or the PGR
Wells and PGR Leases except for the purpose of evaluating, negotiating and
completing the transactions contemplated hereby. Information generally known
in
the industry or which has been disclosed to Buyer by third parties, which have
a
right to do so shall not be deemed confidential or proprietary information
for
purposes of this Agreement. If the transactions contemplated by this Agreement
are not consummated, Buyer will return to the Company (or certify that it has
destroyed) all copies of such data and information, including, but not limited
to, financial information, customer lists, business and corporate records,
worksheets, test reports, tax returns, lists, memoranda and other documents
prepared by or made available to Buyer in connection with the transactions.
Notwithstanding the foregoing, Buyer shall be permitted to disclose such
information about the Company and PGR and the transactions contemplated hereby
as shall be legally required; provided that Buyer shall give prior notice of
such disclosure to the Company sufficiently in advance of such disclosure so
that the Company may seek to obtain confidential treatment thereof if available.
7.2 Compliance.
Buyer
shall make all filings with and notifications of governmental authorities,
regulatory agencies and other entities required to be made by Buyer in
connection with the execution and delivery of this Agreement and the
consummation of the transactions contemplated hereby.
7.3 Conditions.
Buyer
shall take all commercially reasonable actions necessary to cause the conditions
set forth in Section 9.2 to be satisfied and to consummate the transactions
contemplated herein as soon as reasonably possible after the satisfaction
thereof.
7.4 Due
Diligence.
(a) Buyer
agrees that it shall, and it shall cause its contractors, subcontractors,
agents, employees and consultants (collectively “Buyer
Representatives”)
to,
conduct and perform Buyer’s due diligence investigation of the Company, PGR and
the PGR Wells and PGR Leases in a good and workmanlike manner and Buyer shall
be
solely responsible for the prompt payment of all costs and expenses incurred
in
connection therewith, including without limitation, all field and laboratory
costs, insurance premiums, consultants’ fees, and attorneys’ and experts’
fees.
(b) Buyer
agrees to indemnify, protect, defend and hold harmless the Company and its
employees, officers, directors, managers, accountants, agents and advisors
and
each of them, in all capacities including individually, from any liability,
claim, cause of action, damage, cost or other expense of every nature whatsoever
including, without limitation, reasonable attorney’s fees, personal injury
claims, loss of use of, or damage to, the assets or business of the Company
or
PGR, incurred as a result of Buyer’s due diligence.
-24-
Exhibit
10.17
(c) Buyer
shall conduct its due diligence in a manner which minimizes interference with
the Company, PGR and their business and operations. Upon completion of due
diligence, Buyer, at its sole cost and expense, shall remove all materials,
equipment, machinery, and other items used by any of Buyer or Buyer
Representatives and, with respect to fields, assets, or real property, repair
and restore such assets and property to their condition as they existed
immediately prior to Buyer’s entry upon and performance of its due
diligence.
7.5 Notification.
Buyer
shall promptly notify the Company in writing if Buyer discovers that any
representation or warranty made in this Agreement was when made, or has
subsequently become, untrue in any respect.
7.6 Payment.
On the
Closing Date, Buyer shall make the payments required pursuant to Section
2.5.
7.7 Deliveries.
On the
Closing Date, Buyer shall execute and deliver to the Company all of the
following:
(a) a
certificate signed by the appropriate officer of Buyer dated as of the Closing
Date to the effect that the statements set forth in paragraphs (a) and (b)
of Section 9.2
are true
and correct;
(b) the
Escrow Agreement, if required; and
(c) a
certificate of good standing with respect to Buyer, issued not more than ten
(10) days prior to the Closing Date by the Secretary of State of the State
of
Delaware.
|
Section
8.
|
[Intentionally
Omitted].
|
|
Section
9.
|
Conditions.
|
9.1 Conditions
to the Obligations of Buyer.
The
obligation of Buyer to consummate this Agreement and the transactions
contemplated hereby are subject to the fulfillment, prior to or at the Closing,
of the following conditions precedent:
(a) Representations;
Warranties; Covenants.
Each of
the representations and warranties of the Company contained in this Agreement
shall be true and correct as of the Closing Date as though made on and as of
the
Closing Date, except for such representations and warranties as are made as
of a
specified date and except for such breaches of representations and warranties
as
do not, individually or in the aggregate, have a material adverse
effect.
(b) No
Proceedings.
There
shall not be instituted or pending any action or proceeding, before any court
or
governmental authority or agency, domestic or foreign, (i) challenging or
seeking to make illegal, or to delay or otherwise directly or indirectly
restrain or prohibit, the consummation of the transactions contemplated hereby
or seeking to obtain material damages in connection with such transactions,
(ii) seeking to prohibit direct or indirect ownership or operation by Buyer
of all or a material portion of the PGR Assets, or to compel Buyer or any of
its
subsidiaries or the Company to dispose of or to hold separately all or a
material portion of the business or assets of Buyer and its subsidiaries or
of
the PGR Assets, as a result of the transactions contemplated hereby, or
(iii) seeking to invalidate or render unenforceable any material provision
of this Agreement or any of the other agreements attached as exhibits hereto.
-25-
Exhibit
10.17
(c) Performance.
The
Company shall have performed in all material respects all of its obligations
hereunder required to be performed by it at or prior to the Closing
Date.
(d) Consents
and Approvals.
The
Company shall have obtained, or caused to be obtained, and delivered to Buyer
each consent and approval in Schedule
3.5
or
Schedule
3.8
that is
required to be delivered at or prior to Closing. The Company shall have made
all
filings and applications with respect to consents or approvals for which filings
or applications are required at or prior to Closing as provided in Schedule
3.5
or
Schedule
3.8.
(e) Contracts.
The
Company shall deliver assignments for those Contracts listed on Schedule 3.14(b)
that are designated as to be assigned to POC at or prior to
Closing.
(f) Closing
Documents.
Buyer
shall have received from the Company all of the documents referred to in
Section 5.6
above.
9.2 Conditions
to Obligations of the Company.
The
obligations of the Company to consummate this Agreement and the transactions
contemplated hereby is subject to the fulfillment, prior to or at the Closing,
of the following conditions precedent:
(a) Representations;
Warranties; Covenants.
Each of
the representations and warranties of Buyer contained in this Agreement shall
be
true and correct as of the Closing Date as though made on and as of the Closing
Date except for such representations and warranties as are made as of a
specified date and except for such breaches of representations and warranties
as
do not, individually or in the aggregate, have a material adverse effect.
(b) No
Proceedings.
There
shall not be threatened, instituted or pending any action or proceeding before
any court or governmental authority or agency, domestic or foreign, (i)
challenging or seeking to make illegal, or to delay or otherwise directly or
indirectly restrain or prohibit, the consummation of the transactions
contemplated hereby or seeking to obtain material damages in connection with
such transactions, (ii) seeking to prohibit direct or indirect ownership or
operation by Buyer of all or a material portion of the PGR Assets, or to compel
Buyer or any of its subsidiaries or the Company to dispose of or to hold
separately all or a material portion of the business or assets of Buyer and
its
subsidiaries or of the PGR Assets, as a result of the transactions contemplated
hereby, and (iii) seeking to invalidate or render unenforceable any
material provision of this Agreement or any of the other agreements attached
as
exhibits hereto.
(c) Performance.
Buyer
shall have performed in all material respects all of its obligations hereunder
required to be performed by it at or prior to the Closing Date.
(d) Payment
of Adjusted Purchase Price.
Buyer
shall have made the payments required pursuant to Section 2.5.
-26-
Exhibit
10.17
(e) Consents
and Approvals.
Buyer
shall have obtained, or caused to be obtained, each consent and approval
required of it in order to complete the transactions contemplated
hereby.
(f) Closing
Documents.
The
Company shall have received from Buyer all of the documents referred to in
Section 7.7
above.
|
Section
10.
|
Termination
of Agreement; Rights to Proceed.
|
10.1
Termination.
At any
time prior to the Closing, this Agreement may be terminated as
follows:
(a) by
mutual
written consent of Buyer and the Company;
(b) by
Buyer
or the Company, if the Closing has not occurred on or before April 1, 2006
(the
“Termination
Date”);
provided that the terminating party is not in material breach of this
Agreement;
(c) by
Buyer
or the Company pursuant to Section 4.4; or
(d) by
either
the Company or Buyer if consummation of the transactions contemplated hereby
would violate a nonappealable final order, decree or judgment of any court
or
governmental body having competent jurisdiction.
The
party
desiring to terminate this Agreement pursuant to Section 10.1(b), (c) or (d)
shall give notice of such termination to the other party.
10.2
Effect
of Termination.
If this
Agreement is terminated as permitted by Section 10.1, such termination
shall be without liability of either party (or any stockholder, member, partner,
director, officer, employee, agent, consultant or representative of such party)
to the other party to this Agreement and the Deposit shall be returned to Buyer;
provided
that
if a
termination under Section 10.1(b) or (d) shall result from the (i) failure
of either party to fulfill a condition to the performance of the obligations
of
the other party, (ii) failure of either party to perform a covenant of this
Agreement or (iii) breach by either party hereto of any representation or
warranty or agreement contained herein (any of (i), (ii) or (iii), a
“Breach”),
then,
in the case of a Breach by Buyer, the Company shall retain the Deposit and
the
retention of the Deposit by the Company in such circumstances shall in no way
limit the amount of damages that may be recovered by the Company from Buyer
with
respect to Losses suffered as a result of Buyer’s Breach (with the Deposit to be
applied against any damages awarded against Buyer), and in the case of a Breach
by the Company, Buyer shall have the right to pursue all available legal and
equitable remedies including, without limitation, specific performance. In
the
case of a termination by Buyer under Section 10.1(c), the return to Buyer of
the
Deposit shall be Buyer’s sole and exclusive remedy against the Company, and the
Company shall have no further liability to Buyer. The provisions of Sections
7.1, 11.1, 11.6 and 11.7 shall survive any termination hereof pursuant to this
Section 10.
-27-
Exhibit
10.17
|
Section
11.
|
Miscellaneous.
|
11.1
Fees
and Expenses.
Each
party shall pay its own expenses and costs associated with the preparation
and
negotiation of this Agreement and the consummation of the transactions
contemplated hereby.
11.2
Survival
of Representations and Warranties.
All
representations and warranties made by the Company or Buyer shall survive the
Closing until the first anniversary of the Closing Date (the “Survival
Period”).
All
covenants made by the Company or Buyer shall survive until June 15,
2009.
11.3
Indemnification
by the Company.
From
and after Closing, and subject to Section 11.5, the Company shall indemnify
and
hold harmless Buyer and its representatives, stockholders, controlling persons,
and Affiliates (the “Buyer
Indemnified Persons”)
for,
and will pay to the Buyer Indemnified Persons the amount of, any Loss arising,
directly or indirectly, from or in connection with: (a) any Breach by the
Company of any representation or warranty made by the Company in this Agreement;
and (b) any Breach by the Company of any covenant or obligation of the Company
in this Agreement.
11.4
Indemnification
by Buyer.
From
and after Closing, and subject to Section 11.5, Buyer shall indemnify and hold
harmless each the Company and its Affiliates (the “Seller
Indemnified Persons”)
for,
and will pay to the Seller Indemnified Persons the amount of, any Loss arising,
directly or indirectly, from or in connection with: (a) any Breach by Buyer
of
any representation or warranty made by Buyer in this Agreement and (b) any
Breach by Buyer of any covenant or obligation of Buyer in this
Agreement.
11.5
Limitations
on Indemnity.
Neither
party will have any liability under Section 11.3 or 11.4 as the case may be
for
indemnification with respect to any representation or warranty unless the party
seeking indemnification notifies the indemnifying party of a claim in writing
specifying the claim in reasonable detail prior to the end of the Survival
Period. The Company shall not have any liability for indemnification with
respect to matters described in Section 11.3(a) or, to the extent relating
to
any failure to perform or comply prior to the Closing Date, Section 11.3(b),
until the total of all Losses with respect to such matters exceeds $750,000
and
then only for the amount by which such Losses exceeds $750,000, provided
that
the
foregoing deductible shall not apply to any Breach of a representation, warranty
or covenant relating to income taxes or with respect to Section 5.1(b) and
(d),
and the first sentence of Section 5.4. The Company shall not have any liability
for indemnification with respect to Losses suffered by the Buyer Indemnified
Persons, in the aggregate, in excess of $15,000,000, provided
that
the
foregoing limitation shall not apply to any Breach of a representation, warranty
or covenant relating to income taxes.
11.6
Governing
Law; Consent to Jurisdiction.
This
Agreement and all disputes, actions or proceedings arising out of or relating
to
this Agreement or the negotiation, validity or performance hereunder or the
transactions contemplated hereby and/or the rights and obligations of the
parties to this Agreement shall be governed by and construed in accordance
with
the internal laws of the State of Delaware, without regard to its conflict
of
laws provisions. Each of the parties hereto hereby irrevocably and
unconditionally consents to the jurisdiction of the Center for Public Resources
to resolve any such dispute, action or proceeding (except with respect to
any
equitable remedy to which a party is entitled), and further consents to the
jurisdiction of the courts of the State of Colorado and the United States
District Court for the District of Colorado for the purpose of enforcing
the
arbitration provisions of Section 11.7 and pursuing any equitable remedy.
Each of the parties hereto hereby irrevocably and unconditionally waive any
objection to the laying of venue of any such dispute, action or proceeding
before the Center for Public Resources based on a lack of personal jurisdiction
or the laying of venue, and hereby further irrevocably and unconditionally
waive
and agree not to plead or claim in any court that arbitration before the
Center
for Public Resources has been brought in an inconvenient forum. Each of the
parties hereto further agree that service of process, summons, notice or
document by U.S. registered mail to such party’s address set forth in
Section 11.8 hereof shall be effective service of process for any such
dispute, action or proceeding brought against such party in any such
court.
-28-
Exhibit
10.17
11.7
Arbitration.
Any
dispute arising out of or relating to this Agreement or the breach, termination
negotiation, or validity hereof and/or the rights or obligations of the parties
arising out of or relating to this agreement or the breach, termination,
negotiation, or validity hereof shall be finally settled by binding arbitration
conducted expeditiously in accordance with the Center for Public Resources
Rules
for Nonadministered Arbitration of Business Disputes (the “CPR
Rules”).
The
Center for Public Resources shall appoint a neutral advisor from its National
CPR Panel. The arbitration shall be governed by the United States Arbitration
Act, 9 U.S.C. §§1-16, and judgment upon the award rendered by the
arbitrators may be entered by any court having jurisdiction thereof. The place
of arbitration shall be Denver, Colorado.
Such
proceedings shall be administered by the neutral advisor in accordance with
the
CPR Rules as he/she deems appropriate, however, such proceedings shall be guided
by the following agreed upon procedures:
(a) mandatory
exchange of all relevant documents, to be accomplished within forty-five (45)
days of the initiation of the procedure;
(b) no
other
discovery;
(c) hearings
before the neutral advisor which shall consist of a summary presentation by
each
side of not more than three hours; such hearings to take place on one or two
days at a maximum; and
(d) decision
to be rendered not more than ten (10) days following such hearings.
Notwithstanding
anything to the contrary contained herein, the provisions of this
Section 11.7 shall not apply with respect to any equitable remedies to
which any party may be entitled.
11.8
Notices.
Any
notice, request, demand or other communication required or permitted hereunder
shall be in writing and shall be deemed to have been given (i) if delivered
or sent by facsimile transmission, upon acknowledgment of receipt by the
recipient, (ii) if sent by a nationally recognized overnight courier,
properly addressed with postage prepaid, on the next business day (or Saturday
or Sunday if sent for delivery on such days), (iii) or if sent by
registered or certified mail, upon the earlier of the date on which receipt
is
acknowledged or the date which is three (3) days after deposit in United States
post office facilities properly addressed with postage prepaid. All notices
to a
party will be sent to the addresses set forth below or to such other address
or
person as such party may designate by notice to each other party
hereunder:
-29-
Exhibit
10.17
|
TO
BUYER:
|
|
|
Berry
Petroleum Company
|
|
|
5201
Truxtun Avenue, Suite 300
|
|
|
Bakersfield,
California 93309-0640
|
|
|
Attn:
Land Manager
|
|
|
Fax:
(661) 616-3886
|
|
|
Tel:
(661) 616-3900
|
|
|
With
copies to:
|
|
|
Musick,
Peeler & Garrett LLP
|
|
|
200
North Westlake Boulevard, Suite 204
|
|
|
Westlake
Village, California 91362
|
|
|
Attn:
Laura McAvoy
|
|
|
Fax:
(805) 418-3101
|
|
|
Tel:
(805) 418-3115
|
|
|
and
|
|
|
Holland
& Hart LLP
|
|
|
555
Seventeenth Street, Suite 2700
|
|
|
Denver,
Colorado 80201
|
|
|
Attn:
Davis O’Connor
|
|
|
Fax:
(303) 295-8261
|
|
|
Tel:
(303) 295-8000
|
|
|
If
to Company:
|
|
|
Orion
Energy Partners L.P.
|
|
|
1675
Broadway, Suite 2000
|
|
|
Denver,
CO 80202
|
|
|
Attn:
General Partner
|
|
|
Fax:
(303) 595-3043
|
|
|
Tel:
(303) 595-3030
|
|
-30-
Exhibit
10.17
|
With
a copy to:
|
|
|
Davis
Graham & Stubbs LLP
|
|
|
1550
Seventeenth Street, Suite 500
|
|
|
Denver,
CO 80202
|
|
|
Attn:
Chris Richardson
|
|
|
Fax:
(303) 893-1379
|
|
|
Tel:
(303) 892-9400
|
Any
notice given hereunder may be given on behalf of any party by his counsel or
other authorized representatives.
11.9 Entire
Agreement.
This
Agreement, including the Schedules and Exhibits hereto, reflects the entire
agreement of Buyer and the Company with respect to its subject matter, and
replaces and supersedes the Original Agreement and all previous written or
oral
negotiations, commitments and writings. The Original Agreement is hereby
terminated and all rights and obligations of the parties thereto are hereby
terminated and discharged.
11.10
Severability.
Whenever possible, each provision of this Agreement will be interpreted in
such
manner as to be effective and valid and valid under applicable law, but if
any
provision of this Agreement is held to be prohibited by or invalid under
applicable law, such provision will be ineffective only to the extent of such
prohibition or invalidity, without invalidating the remainder of such provision
or the remaining provisions of this Agreement.
11.11
Assignability;
Binding Effect.
This
Agreement may not be assigned by any party hereto without the prior written
consent of the other parties hereto. This Agreement shall be binding upon and
enforceable by, and shall inure to the benefit of, the parties hereto and their
respective successors and permitted assigns.
11.12
Captions
and Gender.
The
captions in this Agreement are for convenience only and shall not affect the
construction or interpretation of any term or provision hereof. The use in
this
Agreement of the masculine pronoun in reference to a party hereto shall be
deemed to include the feminine or neuter, as the context may
require.
11.13
Execution
in Counterparts/Third Party Beneficiaries.
For the
convenience of the parties and to facilitate execution, this Agreement may
be
executed in two or more counterparts, each of which shall be deemed an original,
but all of which shall constitute one and the same document. Facsimile
signatures shall constitute original signatures. No provision of this Agreement
is intended to confer upon any Person other than the parties hereto any rights
or remedies hereunder.
11.14
Amendments.
This
Agreement may not be amended or modified, nor may compliance with any condition
or covenant set forth herein be waived, except by a writing duly and validly
executed by Buyer and the Company, or in the case of a waiver, the party waiving
compliance.
-31-
Exhibit
10.17
11.15
Publicity
and Disclosures.
Except
as and to the extent required by law, without the prior written consent of
Buyer, the Company will not and the Company will direct their representatives
not to, make, directly or indirectly, any public comment, statement or
communication with respect to, or otherwise to disclose or to permit the
disclosure of the existence of discussions regarding a transaction between
the
parties or any of the terms, conditions, or other aspects of the transaction.
If
the Company is required by law to make any such disclosure, it must first
provide to Buyer the content of the proposed disclosure, the reasons that such
disclosure is required by law, and the time and place that the disclosure will
be made and afford Buyer a reasonable opportunity to comment upon and request
changes in the disclosure. In the period before Closing, prior to Buyer making
any press release or public disclosure regarding this Agreement or the
transaction between the parties, Buyer will provide the Company with relevant
portions of any such disclosure and afford the Company a reasonable opportunity
to comment and request changes to such disclosure.
11.16
Disclosure
Schedules.
The
representations and warranties contained in Section 3 are qualified by reference
to the Disclosure Schedules attached hereto. The Disclosure Schedules are not
intended to constitute, and shall not be construed as constituting,
representations or warranties of the Company except as and to the extent
provided in this Agreement. The Disclosure Schedules may include items or
information which the Company is not required to disclose under this Agreement;
disclosure of such items or information shall not affect (directly or
indirectly) the interpretation of this Agreement or the scope of the disclosure
obligation of the Company under the Agreement. Inclusion of information in
the
Disclosure Schedules shall not be construed as an admission that such
information is material to the Company or the financial position or results
of
operation of the PGR Assets or the Company.
Cross
references that may be contained in certain of the Disclosure Schedules to
other
Disclosure Schedules should not be regarded as all-inclusive. Information
contained in various Disclosure Schedules or sections and subsections of the
Disclosure Schedules may be applicable to other Disclosure Schedules or sections
and subsections. Every matter, document or item referred to, set forth or
described in one Disclosure Schedule shall be deemed to be disclosed under
each
and every part, category or heading of that Disclosure Schedule and all other
Disclosure Schedules and shall be deemed to qualify the representations and
warranties of the Company in the Agreement, to the extent such matter, document
or item may apply. Headings have been inserted on sections of the Disclosure
Schedules for the convenience of reference only and shall to no extent affect
the construction or interpretation of any of the provisions of the Agreement
or
the Disclosure Schedules.
-32-
Exhibit
10.17
IN
WITNESS WHEREOF the parties hereto have caused this Agreement to be executed
as
of the date first set forth above.
|
BUYER
|
|||
|
BERRY
PETROLEUM COMPANY
|
|||
|
By:
|
/s/ Michael Duginski | ||
|
Name:
|
Michael Duginski | ||
|
Title:
|
Executive Vice President | ||
|
COMPANY
|
|||
|
ORION
ENERGY PARTNERS L.P.
|
|||
|
By:
Orion Energy Partners, Inc., its General Partner
|
|||
|
By:
|
/s/ Daniel G. Blanchard | ||
|
Name:
|
Daniel G. Blanchard | ||
|
Title:
|
Executive Vice President | ||
-33-
Exhibit
23.1
CONSENT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We
hereby
consent to the incorporation by reference in the Registration Statement on
Form
S-8
(Nos.
333-62871, 333-62799, 333-98379 and 333-127018) of Berry Petroleum Company
of
our report dated March 1, 2006 relating to the financial statements,
management’s assessment of the effectiveness of internal control over financial
reporting and the effectiveness of internal control over financial reporting,
which appears in this Form 10-K.
/s/
PricewaterhouseCoopers LLP
Los
Angeles, California
March
3,
2006
1
Exhibit
23.2
DeGolyer
and MacNaughton
5001
Spring Valley Road
Suite
800
East
Dallas,
Texas 75244
March
1,
2006
Berry
Petroleum Company
5201
Truxtun Avenue, Suite 300
Bakersfield,
California 93309-0640
Gentlemen:
In
connection with the Annual Report on Form 10-K for the fiscal year ended
December 31, 2005, (the Annual Report) of Berry Petroleum Company (the Company),
we hereby consent to (i) the use of and reference to our “Appraisal Report as of
December 31, 2005 on Certain Properties owned by Berry Petroleum Company,”
“Appraisal Report as of December 31, 2004 on Certain Properties owned by Berry
Petroleum Company,” and “Appraisal Report as of December 31, 2003 on Certain
Properties owned by Berry Petroleum Company,” (the “Reports”), under the
captions “Business” and “Oil and Gas Properties” in Item 1 of the Annual Report,
under the caption “Selected Financial Data” in Item 6 of the Annual Report, and
under the caption “Supplemental Information About Oil & Gas Producing
Activities (Unaudited)” in Item 8 of the Annual Report; and (ii) the use of
and reference to the name DeGolyer and MacNaughton as the independent petroleum
engineering firm that prepared the Reports under such items; provided, however,
that since the cash-flow calculations in the Annual Report include estimated
income taxes not included in the Reports, we are unable to verify the accuracy
of the cash-flow values in the Annual Report.
Very
truly yours,
/s/
DeGOLYER and MacNAUGHTON
1
Exhibit 31.1
Certification
of Chief Executive Officer
Pursuant
to Section 302 of Sarbanes Oxley Act of 2002
I,
Robert
F. Heinemann, President, Chief Executive Officer, and Director certify that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Berry Petroleum Company
(the
Company);
|
||
|
|
||||
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make
the
statements made, in light of the circumstances under which such
statements
were made, not misleading with respect to the period covered by
this
report;
|
||
|
|
||||
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial
information
included in this report, fairly present in all material respects
the
financial condition, results of operations and cash flows of the
Company
as of, and for, the periods presented in this annual
report;
|
||
|
|
||||
|
|
4.
|
The
Company’s other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined
in Exchange
Act Rules 13a - 15(e) and 15d - (e) and internal control over
financial reporting (as defined in Exchange Act Rules 13a - 15(f)
and 15d
- 15(f)) for the Company and have:
|
||
|
|
a)
|
designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the Company is made known
to us by
others within those entities, particularly during the period in
which this
annual report is being prepared;
|
||
|
|
||||
|
|
b)
|
designed
such internal control over financial reporting, or caused such
internal
control over financial reporting to be designated under our supervision,
to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
||
|
|
c)
|
evaluated
the effectiveness of the Company’s disclosure controls and procedures and
presented in this report our conclusions abut the effectiveness
of the
disclosure controls and procedures as of the end of the period
covered by
this report based on such evaluation; and
|
||
|
|
||||
|
|
d)
|
disclosed
in this report any change in the Company’s internal control over financial
reporting that occurred during the Company’s most recent fiscal quarter
that has materially affected or is reasonably likely to materially
affect
the Company’s internal control over financial reporting.
|
||
|
|
5.
|
The
Company’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting,
to the
Company’s auditors and the audit committee of the Company’s board of
directors:
|
|
|
a)
|
all
significant deficiencies and material weaknesses in the design
or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the Company’s ability to record,
process, summarize and report financial information and have identified
for the registrant’s auditors any material weaknesses in internal
controls; and
|
||
|
|
||||
|
|
b)
|
any
fraud, whether or not material, that involves management or other
employees who have a significant role in the Company’s internal controls
over financial reporting.
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
/s/
Robert F. Heinemann
|
|
||
|
|
Robert
F. Heinemann
|
|
||
|
March
3, 2006
|
President,
Chief Executive Officer, and Director
|
|
||
1
Exhibit 31.2
Certification
of Chief Financial Officer
Pursuant
to Section 302 of Sarbanes Oxley Act of 2002
I,
Ralph
J. Goehring, Executive Vice President and Chief Financial Officer, certify
that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Berry Petroleum Company
(the
Company);
|
||
|
|
||||
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make
the
statements made, in light of the circumstances under which such
statements
were made, not misleading with respect to the period covered by
this
report;
|
||
|
|
||||
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial
information
included in this report, fairly present in all material respects
the
financial condition, results of operations and cash flows of the
Company
as of, and for, the periods presented in this annual
report;
|
||
|
|
||||
|
|
4.
|
The
Company’s other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined
in Exchange
Act Rules 13a - 15(e) and 15d - (e) and internal control over
financial reporting (as defined in Exchange Act Rules 13a - 15(f)
and 15d
- 15(f)) for the Company and have:
|
||
|
|
a)
|
designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the Company is made known
to us by
others within those entities, particularly during the period in
which this
annual report is being prepared;
|
||
|
|
||||
|
|
b)
|
designed
such internal control over financial reporting, or caused such
internal
control over financial reporting to be designated under our supervision,
to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
||
|
|
c)
|
evaluated
the effectiveness of the Company’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness
of the
disclosure controls and procedures as of the end of the period
covered by
this report based on such evaluation; and
|
||
|
|
||||
|
|
d)
|
disclosed
in this report any change in the Company’s internal control over financial
reporting that occurred during the Company’s most recent fiscal quarter
that has materially affected or is reasonably likely to materially
affect
the Company’s internal control over financial reporting;
|
||
|
|
5.
|
The
Company’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting
to the
Company’s auditors and the audit committee of the Company’s board of
directors:
|
|
|
a)
|
all
significant deficiencies and material weaknesses in the design
or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the Company’s ability to record,
process, summarize and report financial information;
and
|
||
|
|
||||
|
|
b)
|
any
fraud, whether or not material, that involves management or other
employees who have a significant role in the Company’s internal controls
over financial reporting.
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
/s/
Ralph J. Goehring
|
|
||
|
|
Ralph
J. Goehring
|
|
||
|
March
3, 2006
|
Executive
Vice President and Chief Financial Officer
|
|
||
1
Exhibit 32.1
Certification
of Chief Executive Officer
Pursuant
to Section 906 of Sarbanes Oxley Act of 2002
In
Connection with the Annual Report of Berry Petroleum Company (the “Company”) on
Form 10-K for the period ending December 31, 2005 as filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Robert
F. Heinemann, President, Chief Executive Officer and Director of the Company,
certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the
Sarbanes-Oxley Act of 2002, that:
|
|
1)
|
The
Report fully complies with the requirements of section 13(a) or
15(d) of
the Securities Exchange Act of 1934; and
|
||
|
|
||||
|
|
2)
|
The
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of
the
Company.
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
/s/
Robert F. Heinemann
|
|
||
|
|
Robert
F. Heinemann
|
|
||
|
March
3, 2006
|
President,
Chief Executive Officer and Director
|
|
||
1
Exhibit 32.2
Certification
of Chief Financial Officer
Pursuant
to Section 906 of Sarbanes Oxley Act of 2002
In
Connection with the Annual Report of Berry Petroleum Company (the “Company”) on
Form 10-K for the period ending December 31, 2005 as filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Ralph
J. Goehring, Executive Vice President and Chief Financial Officer of the
Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of
the
Sarbanes-Oxley Act of 2002, that:
|
|
1)
|
The
Report fully complies with the requirements of section 13(a) or 15(d)
of
the Securities Exchange Act of 1934; and
|
||
|
|
||||
|
|
2)
|
The
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
/s/
Ralph J. Goehring
|
|
||
|
|
Ralph
J. Goehring
|
|
||
|
March
3, 2006
|
Executive
Vice President and Chief Financial Officer
|
|
||
|
|
||||
1